From: To: Subject: Date: Beth L. Soliere Bob Stump RE: Invitation to Harvard Electricity Policy Group Scottsdale Session Wednesday, December 07, 2016 4:03:25 PM Dinner starts at 6:30. There is a shuttle from the hotel at 6:20 but I don’t think you will want to take that. You will probably want to have your own “wheels”.   From: Bob Stump Sent: Wednesday, December 07, 2016 12:16 PM To: Beth L. Soliere Subject: Fwd: Invitation to Harvard Electricity Policy Group Scottsdale Session   Do you see when this starts? :-( I don't  Sent from my iPhone Begin forwarded message: From: "Mahoney, Jo-Ann" Date: November 30, 2016 at 2:39:46 PM MST To: Bob Stump Cc: "Gill, Susan" Subject: RE: Invitation to Harvard Electricity Policy Group Scottsdale Session Bob, We are delighted that you can attend!  We will be going to dinner at Sassi, on Doug Little’s recommendation to Ashley.   Of course, you are welcome to bring a guest.  I look forward to seeing you!  Best, Jo-Ann   From: Bob Stump [mailto:bstump@azcc.gov] Sent: Wednesday, November 30, 2016 4:30 PM To: Mahoney, Jo-Ann Subject: Re: Invitation to Harvard Electricity Policy Group Scottsdale Session   Jo-Ann, this is a great agenda - thanks, and I'm looking forward to it! My last HEPG (as an elected, at least!).  Please let me know if I can be of help.  Bob Sent from my iPhone On Nov 29, 2016, at 12:06 PM, Mahoney, Jo-Ann wrote: Dear Bob,   I hope this finds you well.  As you know, our next session will be held in Scottsdale on Thursday-Friday, December 8-9, 2016 at the Four Seasons Troon North.  I apologize for the late notice, but it took Bill a very long time to put this meeting together.  Our Thursday panels will focus on:  energy storage policy and the dissonance between competitive markets and resource preference mechanisms.  On Friday morning we will turn our attention to climate policy given the recent elections. (Agenda attached.)   You are welcome to attend as much of the meeting as your schedule allows.   We would also invite you to join us at our conference reception and dinner on Thursday evening.    We hope that you will be with us at the next HEPG session.  Kindly return the registration form to Susan Gill in our office.   Best, Jo-Ann Mahoney   Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu     Policy Dissonance: Pursuing Contradictory,  Perhaps Irreconcilable, Paths of Competitive Markets and Choosing Resource Preferences   In looking at the evolution of electricity markets over the past few years, it is possible to conclude that we are, perhaps unintentionally, pursuing two contradictory -- perhaps even irreconcilable -- goals. On the one hand, we have, over the past two or three decades been committed to a fully competitive generating market, and in many states, competitive retail supply model. At the same time, through subsidies, cross-subsidies, and set aside markets, we have been putting in place (or attempting to do so) mechanisms to identify resource preference in ways that appear designed to alter results that the market may otherwise produce.  These mechanisms include, among other measures, renewable portfolio standards, favorable pricing for non-dispatchable resources such as rooftop solar (e.g. retail net metering and “value” pricing), special treatments for non-emitting generators such as ZECs for nuclear plants, state mandated (or approved) “reliability” decisions affording special treatment to favored plants and efforts, and various efforts to manipulate capacity markets. Indeed, developing a robust, competitive, emissions trading market has also been handicapped by similar efforts to explicitly identifying preferred resources. How seriously are these trends undermining competition in the market place? Are we, perhaps inadvertently, turning away from markets and back toward the old regulatory model? Or, are these divergent trends reconcilable in some fashion, and how?   Treatment of Storage Resources Storage is an increasing focus in electricity markets, but it is still highly uncertain as to how it should be viewed and treated by regulators. Should storage be allowed to participate as generation, transmission or another asset type? Can storage serve multiple purposes in one market? How can asset owners secure cost recovery in regulated and competitive markets? Is it  inherent that traditional transmission and/utilities must own the asset? How might owners/operators of intermittent resources use storage to reduce intermittency and how does that affect its treatment on a regulatory level? To what extent should storage be treated as energy or capacity, or as an ancillary service provider? Is it necessary or even useful to subsidize storage in order to accelerate its evolution into commercially viability?  Should storage at the distribution level be treated similarly to storage at on the high voltage system? Should the pricing of distributed intermittent resources be done in such a way as to incentivize the installation of storage? A Window of Opportunity: Changing Climate Policy Given the sudden shift in the political tectonic plates, there may be a window of opportunity to refashion major aspects of the electricity system.  The confluence of a possible major Federal tax reform, expanded spending on infrastructure investment, and redirection of national climate policy creates a new environment.  Tax reform and national infrastructure spending could make the revenue raising aspects of a carbon tax part of the solution.  And a carbon tax could be a central part of a major change in approach to accounting for the costs of energy externalities, allowing efficient approaches that replace other more intrusive and expensive approaches to environmental protection.  Part of this discussion will accentuate the debate on the social cost of carbon in this context.  The subject is both controversial and important.  How do we define and estimate the social cost of carbon?  What do we know about the key inputs and uncertainties?  How do we translate policy analysis into a workable system for a carbon tax?  How would a national carbon tax interact with state policies for cleaner energy?  What current or planned cleaner energy policies would or should change if there is a carbon tax?  What role will a carbon tax play in our energy future?     From: To: Subject: Date: Attachments: Beth L. Soliere Bob Stump FW: Invitation to Harvard Electricity Policy Group Scottsdale Session Wednesday, December 07, 2016 2:05:55 PM Registration Form - December 2016.docx ATT00001.htm HEPG_12_8-9_DraftAgenda-2.docx ATT00002.htm Here is the draft agenda.   From: Bob Stump Sent: Tuesday, November 29, 2016 2:44 PM To: Beth L. Soliere Subject: Fwd: Invitation to Harvard Electricity Policy Group Scottsdale Session   Sent from my iPhone Begin forwarded message: From: "Mahoney, Jo-Ann" Date: November 29, 2016 at 12:06:25 PM MST To: "bstump@azcc.gov" Subject: FW: Invitation to Harvard Electricity Policy Group Scottsdale Session Dear Bob,   I hope this finds you well.  As you know, our next session will be held in Scottsdale on Thursday-Friday, December 8-9, 2016 at the Four Seasons Troon North.  I apologize for the late notice, but it took Bill a very long time to put this meeting together.  Our Thursday panels will focus on:  energy storage policy and the dissonance between competitive markets and resource preference mechanisms.  On Friday morning we will turn our attention to climate policy given the recent elections. (Agenda attached.)   You are welcome to attend as much of the meeting as your schedule allows.   We would also invite you to join us at our conference reception and dinner on Thursday evening.    We hope that you will be with us at the next HEPG session.  Kindly return the registration form to Susan Gill in our office.   Best, Jo-Ann Mahoney   Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu     Policy Dissonance: Pursuing Contradictory,  Perhaps Irreconcilable, Paths of Competitive Markets and Choosing Resource Preferences   In looking at the evolution of electricity markets over the past few years, it is possible to conclude that we are, perhaps unintentionally, pursuing two contradictory -perhaps even irreconcilable -- goals. On the one hand, we have, over the past two or three decades been committed to a fully competitive generating market, and in many states, competitive retail supply model. At the same time, through subsidies, crosssubsidies, and set aside markets, we have been putting in place (or attempting to do so) mechanisms to identify resource preference in ways that appear designed to alter results that the market may otherwise produce.  These mechanisms include, among other measures, renewable portfolio standards, favorable pricing for non-dispatchable resources such as rooftop solar (e.g. retail net metering and “value” pricing), special treatments for non-emitting generators such as ZECs for nuclear plants, state mandated (or approved) “reliability” decisions affording special treatment to favored plants and efforts, and various efforts to manipulate capacity markets. Indeed, developing a robust, competitive, emissions trading market has also been handicapped by similar efforts to explicitly identifying preferred resources. How seriously are these trends undermining competition in the market place? Are we, perhaps inadvertently, turning away from markets and back toward the old regulatory model? Or, are these divergent trends reconcilable in some fashion, and how?   Treatment of Storage Resources Storage is an increasing focus in electricity markets, but it is still highly uncertain as to how it should be viewed and treated by regulators. Should storage be allowed to participate as generation, transmission or another asset type? Can storage serve multiple purposes in one market? How can asset owners secure cost recovery in regulated and competitive markets? Is it  inherent that traditional transmission and/utilities must own the asset? How might owners/operators of intermittent resources use storage to reduce intermittency and how does that affect its treatment on a regulatory level? To what extent should storage be treated as energy or capacity, or as an ancillary service provider? Is it necessary or even useful to subsidize storage in order to accelerate its evolution into commercially viability?  Should storage at the distribution level be treated similarly to storage at on the high voltage system? Should the pricing of distributed intermittent resources be done in such a way as to incentivize the installation of storage? A Window of Opportunity: Changing Climate Policy Given the sudden shift in the political tectonic plates, there may be a window of opportunity to refashion major aspects of the electricity system.  The confluence of a possible major Federal tax reform, expanded spending on infrastructure investment, and redirection of national climate policy creates a new environment.  Tax reform and national infrastructure spending could make the revenue raising aspects of a carbon tax part of the solution.  And a carbon tax could be a central part of a major change in approach to accounting for the costs of energy externalities, allowing efficient approaches that replace other more intrusive and expensive approaches to environmental protection.  Part of this discussion will accentuate the debate on the social cost of carbon in this context.  The subject is both controversial and important.  How do we define and estimate the social cost of carbon?  What do we know about the key inputs and uncertainties?  How do we translate policy analysis into a workable system for a carbon tax?  How would a national carbon tax interact with state policies for cleaner energy?  What current or planned cleaner energy policies would or should change if there is a carbon tax?  What role will a carbon tax play in our energy future?     REGISTRATION FORM HEPG EIGHTY-FIFTH PLENARY SESSION THURSDAY AND FRIDAY, DECEMBER 8-9, 2016 FOUR SEASONS TROON NORTH SCOTTSDALE, ARIZONA TO: HARVARD ELECTRICITY POLICY GROUP John F. Kennedy School of Government FROM: Name Title Affiliation Address Phone E-mail __________________________________ ______YES, I will be able to attend the HEPG Plenary Session. ______ NO, I will not be able to attend the meeting. ______ I would like to send my designee: Name Title Address Phone E-mail ___________________________ ___________________________ ___________________________ ___________________________ ___________________________ ___________________________ HOTEL INFORMATION We have reserved a block of rooms at the Four Seasons Troon North for the evenings of Wednesday, December 7 and Thursday, December 8. Our HEPG room rate is $270 per night. The hotel will honor the conference rate 3 days prior and 3 days after on a space available basis. Please make your reservation directly with the hotel at (480) 515-5700 and mention Harvard Electricity Policy Group to guarantee the HEPG conference rate. Please note that the reservation deadline is Friday, November 18. The Four Seasons Troon North is located at 10600 East Crescent Moon Drive in Scottsdale, Arizona. To register for the session, please e-mail this reply form to: susan_gill@hks.harvard.edu HARVARD ELECTRICITY POLICY GROUP HARVARD ELECTRICITY POLICY GROUP EIGHTY-FIFTH PLENARY SESSION The Four Seasons Troon North Scottsdale, AZ THURSDAY AND FRIDAY, DECEMBER 8-9, 2016 DRAFT AGENDA Thursday, December 8 8:30 am Breakfast and Informal Discussion 9:00 am Session One. Treatment of Storage Resources Storage is an increasing focus in electricity markets, but it is still highly uncertain as to how it should be viewed and treated by regulators. Should storage be allowed to participate as generation, transmission or another asset type? Can storage serve multiple purposes in one market? How can asset owners secure cost recovery in regulated and competitive markets? Is it inherent that traditional transmission owners and/or utilities must own the asset? How might owners/operators of intermittent resources use storage to reduce intermittency and how does that affect its treatment on a regulatory level? To what extent should storage be treated as energy or capacity, or as an ancillary service provider? Is it necessary or even useful to subsidize storage in order to accelerate its evolution into commercial viability? Should storage at the distribution level be treated similarly to storage on the high voltage system? Should the pricing of distributed intermittent resources be done in such a way as to incentivize the installation of storage? Haresh Kamath, Electric Power Research Institute Julie Blunden, CalCEF Catalyst and CalCharge Stu Bresler, PJM Interconnection Jim Wilde, Arizona Public Service HEPG Draft Agenda, December 8-9, 2016 Thursday, December 8 (cont’d) 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Lunch 1:15 pm Session Two. Policy Dissonance: Pursuing Contradictory, Perhaps Irreconcilable, Paths of Competitive Markets and Choosing Resource Preferences In looking at the evolution of electricity markets over the past few years, it is possible to conclude that we are, perhaps unintentionally, pursuing two contradictory -- perhaps even irreconcilable -- goals. On the one hand, we have, over the past two or three decades been committed to a fully competitive generating market, and in many states, competitive retail supply model. At the same time, through subsidies, cross-subsidies, and set aside markets, we have been putting in place (or attempting to do so) mechanisms to identify resource preference in ways that appear designed to alter results that the market may otherwise produce. These mechanisms include, among other measures, renewable portfolio standards, favorable pricing for non-dispatchable resources such as rooftop solar (e.g. retail net metering and “value” pricing), special treatments for non-emitting generators such as ZECs for nuclear plants, state-mandated (or approved) “reliability” decisions affording special treatment to favored plants and efforts, and various efforts to manipulate capacity markets. Indeed, developing a robust, competitive, emissions trading market has also been handicapped by similar efforts to explicitly identify preferred resources. How seriously are these trends undermining competition in the market place? Are we, perhaps inadvertently, turning away from markets and back toward the old regulatory model? Or, are these divergent trends reconcilable in some fashion, and how? Bernard Neenan, Electric Power Research Institute Michael Wara, Stanford Law School Jay Morrison, National Rural Electric Cooperative Robert Borlick, Borlick & Associates 2:45 pm Coffee Break 3:00 pm Discussion 4:15 pm Adjourn 6:00 pm Reception and Dinner HEPG Draft Agenda, December 8-9, 2016 Friday, December 9 8:30 am Breakfast and Informal Discussion 9:00 am Session Three. A Window of Opportunity: Changing Climate Policy Given the sudden shift in the political tectonic plates, there may be a window of opportunity to refashion major aspects of the electricity system. The confluence of a possible major Federal tax reform, expanded spending on infrastructure investment, and redirection of national climate policy creates a new environment. Tax reform and national infrastructure spending could make the revenue raising aspects of a carbon tax part of the solution. And a carbon tax could be a central part of a major change in approach to accounting for the costs of energy externalities, allowing efficient approaches that replace other more intrusive and expensive approaches to environmental protection. Part of this discussion will accentuate the debate on the social cost of carbon in this context. The subject is both controversial and important. How do we define and estimate the social cost of carbon? What do we know about the key inputs and uncertainties? How do we translate policy analysis into a workable system for a carbon tax? How would a national carbon tax interact with state policies for cleaner energy? What current or planned cleaner energy policies would or should change if there is a carbon tax? What role will a carbon tax play in our energy future? Steve Rose, Electric Power Research Institute Ross McKitrick, University of Guelph, Ontario Jerry Taylor, Niskanen Center Gernot Wagner, Harvard University 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Adjourn From: To: Subject: Date: Attachments: Beth L. Soliere Bob Stump FW: HEPG Advance Reading for Session Two Wednesday, December 07, 2016 2:00:10 PM DM Berkovitz CFTC Administrative Process FDLRv35#2 Mar-Apr 2015.pdf And this   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Friday, October 07, 2016 9:45 AM To: Mahoney, Jo-Ann Cc: Gill, Susan Subject: HEPG Advance Reading for Session Two   Dan Berkovitz has provided this article as background for our HEPG Thursday afternoon discussion on market manipulation cases.    REPORT Futures & Derivatives Law The Journal on the Law of Investment & Risk Management Products ARTICLE REPRINT March 2015 n Volume 35 n The Resurrection of CFTC Administrative Enforcement Proceedings: Efficient Justice or a Biased Forum? BY DAN M. BERKOVITZ The author is a partner in the law firm Wilmer, Cutler, Pickering, Hale and Dorr, LLP, and served as General Counsel of the CFTC from 2009-2013. Summary In the wake of the broad new enforcement authority provided to the Commodity Futures Trading Commission (“CFTC” or “Commission”) in the Dodd-Frank Reform and Consumer Protection Act (“Dodd-Frank”), and severe constraints on agency enforcement resources, the Director of the CFTC’s Division of Enforcement (“Division”) recently stated that the Division intends to increasingly rely on the CFTC’s administrative enforcement process, as opposed to filing a complaint in federal court, to prosecute violations of the Commodity Exchange Act (“CEA”).1 The Division Director explained that the “overwhelming reason for this change is [the agency’s lack of] resources,”2 including its “bandwidth for discovery-intense litigation,”3 but added that the administrative process would also allow the Commission to develop its expertise and the case law with respect to the new statute and regulations.4 The resurrection of the CFTC’s administrative enforcement process would depart from the CFTC’s recent approach to contested enforcement cases. For more than a decade the Division has filed con- tested cases exclusively in federal court— the last contested enforcement case filed before a CFTC administrative law judge (“ALJ”) was in 2001, when the Commission charged Anthony J. DiPlacido with manipulation and attempted manipulation of electricity futures contracts on five occasions in 1998.5 Although the Division has never publicly explained its rationale for avoiding the administrative process during this period, it is generally believed that the Division’s track record in its administrative forum as well as the higher profile of cases filed in federal court were key factors.6 Similar statements by Securities and Exchange Commission (“SEC”) officials signaling the SEC’s intent to rely more on the administrative enforcement process have provoked criticism that administrative proCONTINUED ON PAGE 3 Article REPRINT Reprinted from the Futures & Derivatives Law Report. Copyright © 2015 Thomson Reuters. For more information about this publication please visit legalsolutions.thomsonreuters.com Issue 2 March 2015 n Volume 35 n Issue 2 Futures & Derivatives Law Report © 2015 Thomson Reuters. This publication was created to provide you with accurate and authoritative information concerning the subject matter covered, however it may not necessarily have been prepared by persons licensed to practice law in a particular jurisdiction. The publisher is not engaged in rendering legal or other professional advice, and this publication is not a substitute for the advice of an attorney. If you require legal or other expert advice, you should seek the services of a competent attorney or other professional. For authorization to photocopy, please contact the Copyright Clearance Center at 222 Rosewood Drive, Danvers, MA 01923, USA (978) 750-8400; fax (978) 646-8600 or West’s Copyright Services at 610 Opperman Drive, Eagan, MN 55123, fax (651)687-7551. Please outline the specific material involved, the number of copies you wish to distribute and the purpose or format of the use. For subscription information, please contact the publisher at: west.legalworkspublications@thomson.com Editorial Board STEVEN W. SEEMER Publisher, West Legal Ed Center RICHARD A. MILLER Editor-in-Chief, Prudential Financial Two Gateway Center, 5th Floor, Newark, NJ 07102 Phone: 973-802-5901 Fax: 973-367-5135 E-mail: richard.a.miller@prudential.com MICHAEL S. SACKHEIM Managing Editor, Sidley Austin LLP 787 Seventh Ave., New York, NY 10019 Phone: (212) 839-5503 Fax: (212) 839-5599 E-mail: msackheim@sidley.com PAUL ARCHITZEL Wilmer Cutler Pickering Hale and Dorr Washington, D.C. CONRAD G. BAHLKE Strook & Strook & Lavan LLP New York, NY ANDREA M. CORCORAN Align International, LLC Washington, D.C. Futures & Derivatives Law Report West LegalEdcenter 610 Opperman Drive Eagan, MN55123 © 2015 Thomson Reuters W. IAIN CULLEN Simmons & Simmons London, England IAN CUILLERIER White & Case LLP New York WARREN N. DAVIS Sutherland Asbill & Brennan Washington, D.C. SUSAN C. ERVIN Davis Polk & Wardwell LLC Washington, D.C. RONALD H. FILLER New York Law School DENIS M. FORSTER New York, NY THOMAS LEE HAZEN University of North Carolina at Chapel Hill DONALD L. HORWITZ North American Derivatives Exchange Chicago, IL PHILIP MCBRIDE JOHNSON Washington, D.C. DENNIS KLEJNA New York, NY PETER Y. MALYSHEV Latham & Watkins Washington, D.C., and New York, NY ROBERT M. MCLAUGHLIN Fried, Frank, Harris, Shriver & Jacobson LLP New York, NY CHARLES R. MILLS K&L Gates, LLP Washington, D.C. DAVID S. MITCHELL Fried, Frank, Harris, Shriver & Jacobson LLP New York, NY RITA MOLESWORTH Willkie Farr & Gallagher New York, NY PAUL J. PANTANO Cadwalader, Wickersham & Taft LLP Washington, D.C. GLEN A. RAE Banc of America Merrill Lynch New York, NY KENNETH M. RAISLER Sullivan & Cromwell New York, NY KENNETH M. ROSENZWEIG Katten Muchin Rosenman Chicago, IL THOMAS A. RUSSO American International Group, Inc. New York, NY HOWARD SCHNEIDER Charles River Associates New York, NY LAUREN TEIGLAND-HUNT Teigland-Hunt LLP New York, NY PAUL UHLENHOP Lawrence, Kamin, Saunders & Uhlenhop Chicago, IL SHERRI VENOKUR Venokur LLC New York, NY For authorization to photocopy, please contact the Copyright Clearance Center at 222 Rosewood Drive, Danvers, MA 01923, USA (978) 750-8400; fax (978) 646-8600 or West’s Copyright Services at 610 Opperman Drive, Eagan, MN 55123, fax (651) 687-7551. Please outline the specific material involved, the number of copies you wish to distribute and the purpose or format of the use. This publication was created to provide you with accurate and authoritative information concerning the subject matter covered. However, this publication was not necessarily prepared by persons licensed to practice law in a particular jurisdication. The publisher is not engaged in rendering legal or other professional advice, and this publication is not a substitute for the advice of an attorney. If you require legal or other expert advice, you should seek the services of a competent attorney or other professional. Copyright is not claimed as to any part of the original work prepared by a United States Government officer or employee as part of the person’s official duties. One Year Subscription n 11 Issues n $820.00 (ISSN#: 1083-8562) 2 © 2015 THOMSON REUTERS Futures & Derivatives Law Report CONTINUED FROM PAGE 1 ceedings are inherently unfair due to the absence of the procedural rights that defendants have in federal court, and that an agency cannot both be a prosecutor and an unbiased judge based on the same underlying facts. “These in-house proceedings, which provide far less discovery than does litigation in federal courts and do not operate under the traditional rules of evidence, provide an undeniable ‘insider’ advantage to the SEC,” two critics wrote in a recent op-ed in the The Washington Post.7 Noting the SEC’s favorable track record in its recent administrative proceedings, U.S. District Court Judge Jed Rakoff cautioned that the SEC’s administrative process is “unlikely … to lead to as balanced, careful, and impartial interpretations as would result from having those cases brought in federal court.”8 Concerns regarding the fairness of the agency administrative enforcement process are not new. Shortly after the Commission was first established, former CFTC Chairman William T. Bagley wrote: An inherent and pervasive “undue process” exists at the CFTC and all comparable agencies when the Commission itself is a rule maker, policeman, grand jury, prosecutor, judge and jury with de novo powers in the same case at virtually the same time. The agency has “heard” your case at least three and perhaps more times before you have a hearing. The minds of men are simply not supple enough to judge a defendant’s culpability fairly when vindication of the Commission’s own prosecution and reputation are also at stake in an adversarial proceeding.9 This article first describes the Commission’s administrative process for contested enforcement cases, including noting where the Commission’s procedures are similar to or differ from those available in a federal court proceeding. This article then traces the CFTC’s use (and disuse) of the administrative enforcement process, from the time when the administrative process was the exclusive means available to the agency for prosecuting violations of the CEA, through the current period when the agency has forsaken the use of this process in contested enforcement proceedings. The agency’s prior experience with the administrative process indicates that despite the absence of discovery in agency proceedings, these proceedings can take years to resolve, particularly in cases involving complex © 2015 THOMSON REUTERS March 2015 n Volume 35 n Issue 2 factual and legal issues, such as cases involving allegations of manipulation. Moreover, rather than exhibiting any “home-court” advantage for the Division, the Commission’s decisions in these complex cases often failed to develop the law or make findings in accordance with the positions taken by the Division. Finally, the article examines the extent to which defendants in CFTC administrative proceedings may be able to challenge the fairness of administrative proceedings as well as the agency’s ability to use such proceedings to develop the law as the agency desires.10 Although the courts have traditionally afforded deference to administrative agency determinations in adjudicatory proceedings on questions within the agency’s area of expertise, a number of judges have recently questioned the wisdom of this doctrine, particularly as it applies to administrative legal interpretations made in enforcement actions. The more aggressively the CFTC attempts to use the administrative enforcement process to interpret and apply its new statutory authorities, the more likely that this traditional doctrine will be re-examined. The Administrative Enforcement Process The CFTC’s administrative enforcement authority is statutorily based in Section 6(c) of the CEA. If the Commission has “reason to believe that any person (other than a registered entity) is violating or has violated [the CEA], or any rule, regulation or order” promulgated thereunder, Section 6(c)(4) authorizes the Commission to serve a complaint upon that person, which “shall … contain a description of the charges against the person … [and] … a notice of hearing that specifies the date and location of the hearing regarding the complaint.”11 Section 6(c)(4) (C) authorizes the Commission to hold the hearing itself or to designate an ALJ to conduct the hearing. Section 6(c)(10) also authorizes the Commission to impose sanctions for violations. Based on the evidence received during the hearing, the Commission may prohibit a person from trading on a registered entity, suspend or revoke the registration of any person, or assess civil penalties for the violations, up to the maximum amounts specified in the statute.12 A person subject to any such sanctions imposed by the Commission may seek judicial review of the Commission’s determinations in the U.S. Court of Appeals. The Commission’s Rules of Practice for conducting adjudicatory hearings in enforcement actions are 3 March 2015 n Volume 35 n Issue 2 set forth in Part 10 of the Commission’s regulations. In accordance with CEA Section 6(c)(4)(B), an adjudicatory proceeding is commenced when the Division files a complaint and notice of hearing with the CFTC’s Office of Proceedings.13 The complaint must state the Commission’s legal authority and jurisdiction to conduct the hearing, and the alleged violations of law and the facts upon which the alleged violations are based with sufficient specificity so as to “permit a specific response to each allegation.”14 Following the service of the complaint and notice of a hearing, the respondent must file an answer as to whether the respondent admits, denies, or does not have and is unable to obtain sufficient information to admit or deny each allegation.15 The answer must include a statement of facts supporting each affirmative defense.16 The failure to file an answer within 20 days may result in a default judgment against the respondent.17 Upon the filing of a complaint the Commission’s Office of Proceedings will assign an ALJ to conduct a hearing. Until 2012, the Commission employed two full-time ALJs to conduct its adjudicatory hearings, which generally consisted of both enforcement cases and certain reparations cases involving claims for amounts greater than $30,000.18 In 2012, however, due to the declining adjudicatory caseload, the Commission eliminated its two full-time ALJs and determined it would use “borrowed, detailed or retired ALJs as needed to manage the proceedings formerly handled by the permanent ALJs.”19 The ALJ is responsible for the conduct of the proceeding. The ALJ may administer oaths and affirmations, issue subpoenas, receive relevant evidence and make evidentiary rulings, examine witnesses, hold pre-hearing conferences, and rule on all motions.20 ALJs are independent from the Division – they may not be responsible to or under the supervision of any person performing an investigatory or prosecutorial function.21 Similarly, an ALJ may not be advised by any person performing an investigatory or prosecutorial function with respect to the same or a factually related proceeding, except as witness or counsel.22 Ex parte communications are prohibited during an adjudicatory hearing.23 An ex parte communication is defined as an oral or written communication not on the public record with respect to which reasonable prior notice to all parties is not given. A party or other person that may be adversely affected by a proceeding may not make an ex parte communication that is relevant to the merits of the proceeding to any Commissioner, ALJ, or other Commission employee involved in the decisional process.24 4 Futures & Derivatives Law Report An ALJ may hold one or more pre-hearing conferences to determine the extent to which issues can be clarified, certain facts may be admitted or stipulated, documents authenticated, the number of witnesses limited, evidentiary objections considered, testimony filed, and the conduct of the hearing expedited.25 The ALJ also determines whether any other persons should be permitted to intervene in or be heard during the proceeding.26 Pre-hearing discovery under the Commission’s administrative process is more limited than in federal court under the Federal Rules of Civil Procedure (“Federal Rules”). Generally, although the Commission’s rules provide for each party to disclose to the other party or parties certain information regarding the legal theories and factual information upon which it intends to rely, respondents do not have a right to submit interrogatories or take the depositions of witnesses or potential witnesses, except in limited circumstances. Unlike a trial in federal court, where a party may have the opportunity to take the deposition of a witness prior to trial, the CFTC’s adjudicatory hearing may be the first—and only—opportunity for the respondent to examine a witness and the basis for the witness’s testimony. The Commission’s Rules of Practice require the parties to file a prehearing memorandum that discloses basic information about the case they intend to present. The prehearing memorandum must set forth an outline of the party’s case or defense; the legal theories upon which the party will rely; the identity and geographic location of each witness other than an expert witness, along with a brief summary of the witness’s expected testimony; and a list of documents that the party intends to introduce at the hearing, along with any copies thereof which the other parties do not already have and to which they do not have reasonably ready access.27 With respect to expert witnesses that a party intends to call, the party must identify each such witness and his or her qualifications, provide a list of any publications authored by the witness within the preceding ten years, a list of all cases in which the witness has testified as an expert within the preceding four years, a “complete statement of all opinions to be expressed by the witness and the basis or reasons for those opinions,” and a list of documents, data, or other written material considered by the witness in forming his or her opinion.28 The Division also must disclose certain information to the respondents prior to the hearing. The Division must make available and permit the respondents to make copies of all documents that were produced pursuant to subpoenas issued by the © 2015 THOMSON REUTERS Futures & Derivatives Law Report Division or otherwise obtained by the Division from persons outside the Commission; the subpoenas or other written requests for such documents; and all transcripts, investigative testimony and all exhibits to those transcripts.29 There are several exceptions to these disclosure requirements. The Division may withhold documents that would disclose the identity of a confidential source, confidential investigatory techniques or procedures. The Division may also withhold information that would disclose the market positions, business transactions, trade secrets, or names of customers of any persons other than the respondents, unless such information is relevant to the resolution of the proceeding.30 Information that is privileged from disclosure under other provisions of law also may be withheld.31 All parties have specific disclosure obligations with respect to witness statements.32 Each party must make available to the other party any statement in its possession of any person whom the party expects to call that relates to the anticipated testimony. This obligation covers transcripts of investigative interviews, depositions, trial or other testimony given by the witness, written statements signed by the witness, and substantially verbatim notes of interviews with the witness. The Division must produce witness statements prior to the scheduled hearing date, at a time designated by the ALJ. The respondent must produce its witness statements at the close of the Division’s case at the hearing. The ALJ, upon motion by any party, or upon his or her own initiative, may direct each party to serve upon the other parties a list of documents that they intend to introduce at the hearing. The ALJ may also then direct that each other party file and serve a response disclosing any objections to the authenticity or admissibility of such documents, along with the legal and factual grounds for such objections. After affording each party an opportunity to file briefs as to the authenticity or admissibility of the documents, the ALJ may rule as to whether the documents that are objected to shall be admitted.33 In contrast to the Federal Rules, which generally permit oral depositions or written interrogatories of any person, including parties, the CFTC’s Rules of Practice permit depositions or interrogatories only when a prospective witness will be unable to attend or testify at a hearing due to “age, illness, infirmity, imprisonment or on the basis that he is or will be outside of the United States at the time of the hearing”, the testimony is material, and “it is necessary to take his deposition in the interests of justice.”34 A party seeking to take the deposition of a witness must apply in writing to the ALJ for an order to take © 2015 THOMSON REUTERS March 2015 n Volume 35 n Issue 2 the deposition.35 A deposition may then be used at the hearing, provided that the witness is unable to testify at the hearing, the testimony was taken under oath, and the other parties had a reasonable opportunity to cross-examine the witness at the time the statement was made.36 Rule 10.68 authorizes any party to apply to the ALJ for the issuance of a subpoena requiring a person to testify at the hearing, or to produce “specified documentary or tangible evidence (subpoena duces tecum) at any designated time or place.”37 Another party may move to quash or limit the production, or for a protective order to limit the use or disclosure of such information. The ALJ may deny the application, or impose conditions upon the required production, if he or she considers the request “unreasonable, oppressive, excessive in scope, or unduly burdensome,” or may issue a protective order upon a showing of good cause.38 Although the ALJ may issue a subpoena to compel the attendance of a witness or the production of documents, the Commission does not have independent authority to impose sanctions for refusal to obey an administrative subpoena. Rather, the Commission may apply to federal court to order such person to appear before the ALJ or the Commission to provide testimony or produce documents, and the failure to obey such order of the court may lead to sanctions for contempt.39 Similar to the Federal Rules, however, the procedures for taking an oral deposition of a witness are the same as if the witness were testifying at the hearing. The witness is subject to both direct and cross-examination and the testimony shall be recorded verbatim. Objections to testimony, evidence or the conduct of the parties may be raised for a later ruling by the ALJ, and, if the parties agree, objections to matters testified to in the deposition may also be made at the hearing, even if the objection was not raised during the deposition.40 In order to narrow the issues to be determined at the hearing, prior to the hearing either party may request another party for “admission of the truth of any facts relevant to the pending proceeding.” If the other party objects, “the reasons therefor shall be stated.”41 With respect to the conduct of the hearing, the Rules of Practice provide that “Every party is entitled to due notice of hearings, the right to be represented by counsel, and the right to cross-examine witnesses, present oral and documentary evidence, submit rebuttal evidence, raise objections, make arguments and move for appropriate relief.”42 The ALJ may ensure that the evidence presented is relevant 5 March 2015 n Volume 35 n Issue 2 to the proceeding, and may limit cross-examination to the subject matter of the direct examination and matters affecting the credibility of the witness.43 Although Commission Rule 10.66(c) provides the ALJ with discretion to permit cross-examination as to any matter that is relevant to the issues in the proceeding, without regard to the scope of direct examination,44 the Commission has indicated this should be the exception rather than the rule. In upholding ALJ rulings limiting the scope of cross-examination, the Commission has approvingly referenced Federal Rule of Evidence 611(b), stating that “[c]rossexamination should be limited to the subject matter of the direct examination and matters affecting the credibility of the witness.”45 Commission Rule 10.67 provides a broad standard for the admissibility of evidence: “Relevant, material, and reliable evidence shall be admitted. Irrelevant, immaterial, unreliable and unduly repetitious evidence shall be excluded.”46 A party that objects to the introduction of evidence must “timely and briefly” state the grounds for the objection. Although the Commission is not bound to follow the Federal Rules of Evidence in its adjudicatory hearings, it nonetheless looks to the Federal Rules of Evidence as “guidance and support” in determining whether certain evidence is admissible.47 Thus, for example, the Commission has followed Federal Rule of Evidence 701 with respect to the admissibility of the opinion of a lay witness,48 and Federal Rule of Evidence 702 with respect to the testimony of an expert witnesses.49 The Commission also has adopted the “Brady rule,” which imposes a duty upon the Division to provide to the respondent “all material of which it aware that is arguably exculpatory as to either guilt or punishment.”50 Interlocutory review by the Commission of an ALJ’s ruling is available only in “extraordinary circumstances.”51 Circumstances in which the Commission, in its discretion, may grant interlocutory review include appeals from an adverse ruling on a motion to disqualify an ALJ, appeals from rulings suspending an attorney or denying intervention or limited participation, and appeals from rulings requiring the appearance of a Commission or other government agency employee or the production of Commission records.52 The Commission may also consider interlocutory review where the ALJ certifies to the Commission that the ruling sought to be appealed involves a controlling question of law or policy, immediate appeal may materially advance the ultimate resolution of the issues, and subsequent reversal of the ruling would cause unnecessary delay or expense to the parties.53 6 Futures & Derivatives Law Report Following the conclusion of the hearing, the parties may file proposed findings of fact and conclusions of law, as well as supporting briefs. Oral argument also may be held at the discretion of the ALJ. After the parties have filed their proposed findings of fact, conclusions of law, and supporting briefs, the ALJ will issue his or her initial decision, which is to be based on the record of the proceeding.54 In order to prevail, the Division must demonstrate that the charges “are supported by the weight of the evidence.”55 The “weight of the evidence” standard is equated with the “preponderance of the evidence” standard – i.e., a finding of liability must be supported by the preponderance of the evidence.56 Any party may appeal an ALJ decision, dismissal, or other final disposition to the Commission.57 The Commission also may determine to review an initial decision on its own initiative.58 The Commission ordinarily will consider the whole record on review, but may limit the issues to those presented in the briefs for appeal.59 In reviewing a matter on appeal, the Commission will determine sanctions de novo rather than defer to the assessment of the ALJ.60 The Commission also may choose to grant a motion to hold oral argument.61 If neither party appeals the initial decision or order and the Commission does not undertake review on its own initiative or stay the decision, then the decision becomes final 30 days after it is issued.62 If the proceeding results in an order for the imposition of a civil penalty, the suspension of trading privileges, or the suspension or revocation of a registration, a person may seek judicial review of the order in the U.S. Court of Appeals.63 CFTC Use of the Administrative Process From the passage of the Commodity Exchange Act in 1936 to the passage of the Commodity Futures Trading Commission Act in 1974 (“1974 Act”), which replaced the Commodity Exchange Authority within the Department of Agriculture with the independent, five-member Commission to administer and enforce the CEA, the administrative process was the only avenue for the agency to bring civil actions for violations of the CEA. During this period, the suspension or revocation of a person’s trading privileges on a designated contract market was the sole sanction available to the agency for civil violations of the CEA by non-exchange personnel. The 1974 Act authorized the Commission to impose civil penalties for violations of the CEA through its administrative proceedings and to bring actions © 2015 THOMSON REUTERS Futures & Derivatives Law Report in federal court to enjoin violations.64 The 1974 Act, however, did not provide the federal courts with authority to impose civil penalties for past violations. That authority remained solely with the Commission until 1992, when Congress amended the CEA to authorize the Commission to seek and for the courts to impose “upon a proper showing,” in actions brought by the Commission under Section 6c for injunctive relief, civil penalties for violations of the CEA.65 Thus, only within the past twenty years has the Division had the ability to choose which forum—administrative or judicial—in which to pursue civil penalties for violations of the CEA. Initially, therefore, the law of manipulation was developed through judicial review of administrative cases involving suspensions of trading privileges. In these early judicial cases, such as General Foods Corp. v. Brannan,66 Great Western Food Distributors, Inc. v. Brannan,67 Volkart Bros., Inc. v. Freeman,68 and Cargill, Inc. v. Hardin,69 the courts interpreted the CEA de novo – without according the agency’s position any particular deference. These judicial decisions did not always reach the result or produce the legal standard for manipulation sought by the agency. For example, in General Foods Corp. v. Brannan, the court held, contrary to the agency’s position, that the respondents’ large purchases of rye for the purpose of stabilizing the market did not constitute an unlawful attempt to manipulate or corner the market. The court stated that “the common criteria usual in manipulation or corner cases are deceit, trickery through the spreading of false rumors, concealment of position, the violation of express anti-manipulation controls, or other forms of fraud. None of these elements are claimed or shown to exist in the instant situation.”70 In Volkart, the Fifth Circuit held that a trader’s exploitation of a natural squeeze or corner would not constitute manipulation: “In brief, before the order punishing the petitioners can be sustained, it must appear not only that they profited from a squeeze, but that they intentionally brought about the squeeze by planned action.”71 After the agency sought unsuccessfully to have the Volkart ruling overturned through legislation, it turned to the administrative process to reconcile the conflicting judicial precedents and set forth its view of the appropriate standard.72 In 1977, in In re Hohenberg Bros., the Commission established the two elements of attempted manipulation: “An attempted manipulation requires only an intent to affect the market price of the commodity and some overt act in furtherance of that intent.”73 The Commission © 2015 THOMSON REUTERS March 2015 n Volume 35 n Issue 2 also held that a dominant or controlling position in the market is not a prerequisite for manipulation or attempted manipulation, nor is a profit motive.74 Several years later, in 1982, in In the Matter of Indiana Farm Bureau Coop. Ass’n, the Commission elaborated on the element of intent necessary to support a finding of manipulation. “It must be proven,” the Commission wrote, “that the accused acted (or failed) to act with the purpose or conscious object of causing or effecting a price or price trend in the market that did not reflect the legitimate forces of supply and demand influencing futures prices in the particular market at the time of the alleged manipulative activity.”75 The Commission approvingly cited the holdings in both General Foods and Volkart, stating that it is permissible for traders to seek the best price, even in a congested market, “as long as their trading activity does not have as its purpose the creation of ‘artificial’ or ‘distorted’ prices.” The Commission thus held that where a squeeze arises from natural conditions, and is not intentionally created by a long, “manipulative intent may not be inferred where a long does not exacerbate the congestion itself.”76 In 1987, in In the Matter of Cox, the Commission reviewed both the judicial and administrative precedents and set forth the four-part test that has become the standard for finding manipulation under CEA Section 9(a)(2): (1) that the accused had the ability to influence market prices; (2) that they specifically intended to do so; (3) that artificial prices existed; and (4) that the accused caused the artificial prices.77 The four-part test has been viewed by many as creating an insurmountable hurdle for the Division of Enforcement in proving a manipulation case, largely due to the difficulty in demonstrating the existence of artificial prices and causality.78 As a result of these concerns regarding the four-part test, in the Dodd-Frank Act Congress amended CEA Section 6(c) to also prohibit the use of “any manipulative or deceptive device or contrivance,” based on similar language in Section 10(b) of the Securities and Exchange Act of 1934. Although the Commission’s new anti-manipulation authority has yet to be tested, either in federal court or before the agency, it is widely believed that, based on the precedents interpreting similar language in the securities laws, it will be easier for the Division to meet its burden of proof under the SEC-based standard than under the precedents governing CEA Section 9(a)(2). The last contested case that the Division brought before an administrative judge was In the Matter of Anthony J. DiPlacido, which was filed in 2001, 7 March 2015 n Volume 35 n Issue 2 and concerned manipulative conduct occurring in 1998. Since the early 2000s, the Commission has filed all of its contested enforcement cases in federal court. Because these cases are filed in federal court under Section 6c of the CEA, they have sought both injunctive and other equitable relief as well as the imposition of civil penalties. 79 Despite the general impression that the administrative enforcement process proceeds much more quickly than federal court litigation due to the absence of pre-hearing discovery, the CFTC’s previous experience indicates that the administrative process can be lengthy, particularly in complex cases involving detailed factual issues and significant legal issues. A 1995 study by the General Accounting Office on administrative enforcement cases before the agency during the years 1989 through 1993 found that it took an average of 24 months from issuance of complaint and notice of hearing to initial decision, and then another 24 months from initial decision to appeal decision.80 Complex cases have taken significantly longer. The Commission issued its opinion in the DiPlacido case approximately 7 years after the complaint was filed. Other contested major manipulation cases brought before the agency in the 1970s and 1980s also took many years to resolve: Hohenberg took 6 years, In the Matter of Abrams took 7 years, Indiana Farm Bureau 8 years, and Cox 16 years.81 Moreover, with the exception of the DiPlacido case, in each of these other lengthy manipulation cases the Commission either dismissed or affirmed the ALJ’s dismissal of the complaint. At least with respect to the complex manipulation cases that the Commission has faced in the past, the record does not support either the view that the administrative process quickly or efficiently resolves such cases or that the Division of Enforcement enjoys any particular “home court” advantage when bringing a complex case to the Commission through the adjudicatory process.82 Judicial Review Administrative Procedures The courts have generally rejected due process challenges to the particular administrative procedures used by the CFTC in its adjudications. The courts have held that the CFTC must provide the basic requirements of due process—such as timely notice, an opportunity to be heard before an impartial judge, and an opportunity for cross-examination— but have refused to require the same procedures that 8 Futures & Derivatives Law Report are available in a federal court proceeding, or even to second-guess the particular procedures employed by the agency. In Silverman v. CFTC, the Seventh Circuit Court of Appeals rejected the claim that the failure to permit discovery was a denial of due process.83 “There is no basic constitutional right to pretrial discovery in administrative proceedings,” the court stated. “The Administrative Procedure Act contains no provision for pretrial discovery in the administrative process … and the Federal Rules of Civil Procedure for discovery do not apply to administrative proceedings.”84 The court noted, however, that the due process clause “does insure the fundamental fairness of the administrative hearing,” which includes a “fair trial, conducted in accordance with fundamental principles of fair play and applicable procedural standards established by law.”85 In Gimbel v. CFTC, the Seventh Circuit elaborated that due process requires both timely notice and a meaningful opportunity to be heard, but found that the instant case Commission’s adjudicatory hearing process had provided both.86 The Ninth Circuit also has ruled “‘there is no basic constitutional right to pretrial discovery in [Commission] proceedings.’”87 The Commission’s procedural discretion is not without limits. In Lloyd Carr & Co. v. CFTC, the ALJ refused to reopen the hearing to permit the testimony of a witness who was delayed due to a snowstorm and arrived at the hearing one minute late.88 The Second Circuit held that “Although an ALJ has wide latitude in the conduct of a hearing … administrative convenience or even necessity cannot override the constitutional requirements of due process.”89 The court found “the ALJ abused his discretion in failing to reopen the hearing when the first witness arrived one minute after the hearing was closed.”90 Hence, although the agency has substantial discretion as to the procedures to be used in the conduct of an administrative hearing, courts may step in where the agency’s procedures may affect the fundamental fairness of the proceeding. Findings of Fact Prior to the passage of the Dodd-Frank Act, the CEA included a standard for judicial review of factual findings in enforcement cases. Section 6(c) provided that “the findings of the Commission as to the facts, if supported by the weight of the evidence, shall [be] conclusive.”91 The courts interpreted this standard to be upheld the Commission’s findings must be supported by “the weight—or preponderance—of the evidence.”92 The courts also generally © 2015 THOMSON REUTERS Futures & Derivatives Law Report followed the elaboration of this standard that the Seventh Circuit set forth in Great Western Foods: [T]he function of this court is something other than that of mechanically reweighing the evidence to ascertain in which direction it preponderates; it is rather to review the record with the purpose of determining whether the finder of fact was justified, i.e. acted reasonably, in concluding that the evidence, including the demeanor of the witnesses, the reasonable inferences drawn therefrom and other pertinent circumstances, supported his findings.93 In the Dodd-Frank Act, Congress amended CEA Section 6(c) by including the new fraud-based antimanipulation authority and reorganizing the statutory language regarding the administrative enforcement process from one long paragraph into eleven subsections. Congress did not include in the revised section the previous language establishing the standard of review. Thus, CEA Section 6(c) no longer contains an explicit standard of judicial review for Commission factual findings. It is not clear, however, that the deletion of the “weight of the evidence” standard from CEA Section 6(c) will change the approach of the courts in reviewing agency findings of fact. In the absence of an explicit standard of review within the CEA, a court would likely turn to the standard of review in the Administrative Procedure Act (“APA”) that applies to agency on-the-record adjudications. With respect to factual determinations, Section 706 of the APA provides that “The reviewing court shall … hold unlawful and set aside agency action, findings, and conclusions found to be … (E) unsupported by substantial evidence … or otherwise reviewed on the record of an agency hearing provided by statute … .”94 APA caselaw indicates that the “substantial evidence” standard is distinct from the “weight of the evidence” standard. For example, the D.C. Circuit has stated that substantial evidence under Section 706 can be “something less than the weight of the evidence… . At a minimum however a decision is not supported by substantial evidence unless there is ‘such relevant evidence as a reasonable mind might accept as adequate to support a conclusion.’”95 This articulation of the “substantial evidence” standard of review in the APA does not appear to significantly differ from the standard of review articulated in Great Western Foods and other CFTC © 2015 THOMSON REUTERS March 2015 n Volume 35 n Issue 2 cases, where the courts have declined to reweigh the evidence themselves in order to determine where the preponderance lies, but rather will “review the record with the purpose of determining whether the finder of fact was justified, i.e. acted reasonably, in concluding that the evidence . . supported his findings.”96 There is no indication that Congress intended the deletion of the explicit “weight of the evidence” standard for judicial review in Section 6(c) to affect the burden of proof in the underlying proceedings. Thus, presumably, the Commission still must determine that the weight or preponderance of the evidence supports a finding of liability, and that these findings will continue to be reviewed by the courts for reasonableness. Sanctions The courts will generally review sanctions imposed by the Commission within its authority “only for an abuse of discretion, asking whether [the sanction] is rationally related to the offense.”97 Under this standard, “as long as an agency has ‘articulate[d] a satisfactory explanation for its action including a ‘rational connection between the facts found and the choice made’ … [the court] will uphold its choice of sanctions.”98 Questions of Law In DiPlacido, the Second Circuit set forth the standard of review for legal issues commonly used by the courts of appeal: “Our review of the Commission’s legal judgments is plenary,” but the court also stated that under the doctrine announced by the Supreme Court in Chevron U.S.A., Inc. v. Natural Res. Defense Council it would defer to the agency’s judgments within its area of expertise: “[W]here a question implicates Commission expertise, we defer to the Commission’s decision if it is reasonable.”99 Not all judges have enthusiastically embraced this deferential standard. In Elliott v. CFTC, the Seventh Circuit set forth what it termed two standards of review.100 “If the question presented is ‘of the sort that courts commonly encounter, de novo review is proper.’ … On the other hand, if the Commission’s decision was peculiarly within its area of expertise, we apply a deferential standard and will affirm so long as the decision is reasonable.” The court cautioned, however, that determining which standard to apply to a particular question is “no easy matter,” and that courts “should not automatically abandon heightened review” simply because the matter is within the agency’s expertise. “When the agency 9 March 2015 n Volume 35 n Issue 2 diet is food for the courts on a regular basis, there is little reason for judges to subordinate their own competence to administrative expertness.” Noting that courts “have applied the deferential standard to Commission determinations of the evidence necessary to prove violations of the [CEA] … as well as Commission rules,” the court found that the question of the whether the conduct at issue constituted non-competitive trading on the Chicago Board of Trade was appropriately within the agency’s area of expertise rather than the court’s, and accorded the agency’s determination deference.101 Writing in dissent, Judge Easterbrook scoffed at the notion that the Commission had any special expertise to decide this type of issue. “Ever since Congress began to establish independent agencies in 1887, it has been customary to refer to a commission’s ‘expertise.’ This is a figure of speech, an honorific, rather than a description of commissioners’ backgrounds and skills. It would be more accurate to call commissioners of the CFTC (and other agencies) ‘specialists.’ … Only one of the four Commissioners who participated in the order under review had any experience in the trading pits, and he dissented from the decision under consideration.”102 Judge Easterbrook’s challenge to the notion of Commission “expertise” that should trigger a more deferential standard of review in administrative enforcement cases reflects an unease with deferring to an administrative agency in the adjudicatory context that is similar to Judge Rakoff’s recent criticisms of the administrative enforcement process as a means for the development and interpretation of the law. Other judges have expressed a similar concern. U.S. District Judge Lewis Kaplan, also of the Southern District of New York, recently noted the concern that application of Chevron deference to the SEC’s interpretations of the securities laws in administrative proceedings will “increase the role of the Commission in interpreting the securities laws to the detriment or exclusion of the long standing interpretive role of the courts.”103 “These concerns are legitimate,” Judge Kaplan wrote, “whether born of self-interest or of a person assessment of whether the public interest would be served best by preserving the important interpretive role of Article III courts in construing the securities laws – a role the courts have performed since 1933.”104 Supreme Court Justice Eugene Scalia also recently expressed concerns regarding the doctrine of deference as it applies to executive branch interpretations of statutes that contemplate both criminal and civil enforcement. Writing in dissent to the denial of certiorari in Whitman v. United 10 Futures & Derivatives Law Report States, Justice Scalia disputed the notion that any deference should apply to executive branch interpretations of criminal statutes: “The rule of lenity requires interpreters to resolve ambiguities in criminal laws in favor of defendants,” Justice Scalia stated, as well as “vindicates the principle that only the legislature may define crimes and fix punishments. Congress cannot, throughout ambiguity, effectively leave that function to the courts—much less to the administrative bureaucracy.”105 Justice Scalia’ expansive language indicates he that he is questioning not only the doctrine of deference as it applies to criminal statutes, but also to administrative enforcement of laws that can be enforced either civilly or criminally. Justice Scalia concluded his dissent by stating he would be receptive to granting certiorari “when a petition properly presenting the question comes before us.”106 Hence, although the courts have typically granted deference to the Commission’s legal judgments within its area of expertise, a number of judges may be reluctant to apply the doctrine in circumstances—such as in the adjudicatory rather than rulemaking context—where they believe the courts are at least as well-suited to interpret and apply the law as the agency. In light of these concerns, it is by no means a foregone conclusion that the Commission will continue to be afforded Chevron deference in cases involving aggressive interpretations or applications of the Dodd-Frank law made in the course of agency adjudications. Conclusion The agency’s prior experience with the administrative enforcement process indicate that, despite the absence of discovery for litigants, it could take many years to resolve complex contested cases. Further, the Commission’s decisions in contested manipulation cases often did not produce the results desired by the Division of Enforcement. However, many of these cases occurred several decades ago. It has been well over a decade since the Division of Enforcement sought to litigate a contested enforcement case through the agency’s administrative hearing process. If the Division indeed resurrects the administrative enforcement process for contested cases, the Commission and interested parties in the agency’s administrative proceedings will have an opportunity to raise anew issues concerning appropriate hearing procedures, standards of proof, and the scope and role of judicial review. © 2015 THOMSON REUTERS Futures & Derivatives Law Report NOTES 1. Jean Eaglesham, CFTC Turns Toward Administrative Judges, Wall St. J., Nov. 9, 2014. 2. Id. 3. Stephanie Russell-Kraft, Cash-Strapped CFTC Faces Troubled Return To Admin Court, Law360, Nov. 14, 2014. 4. Stephanie Russell-Kraft , CFTC Plans More Administrative Actions, Criminal Crackdowns, Law360, Nov. 7, 2014. (“We have a host of new provisions under Dodd-Frank that need to have a precedent developed.”). 5. In the Matter of Anthony J. DiPlacido, Comm. Fut. L. Rep. (CCH) P30,970 (CFTC, Nov. 5, 2008). 6. See, e.g., Michael Schroeder, If You’ve Got a Beef With a Futures Broker, This Judge Isn’t For You—In Eight Years at the CFTC, Levine Has Never Ruled in Favor of an Investor, Wall St. J., Dec. 13, 2000. 7. Mark Cuban and Thomas Melsheimer, It is time to rein in the SEC, Washington Post, Dec. 19, 2014. 8. Judge Jed S. Rakoff, Is the S.E.C. Becoming a Law Unto Itself?, PLI Securities Regulation Institute Keynote Address, Nov. 5, 2014 (“the S.E.C. won 100% of its internal administrative hearings in the fiscal year ended September 30, 2014, whereas it won only 61% of its trials in federal court during the same period.”). 9. William T. Bagley, Introduction: A New Body of Law in an Era of Industry Growth, 27 Emory L.J. 849, 851 (1978). 10. For a discussion of constitutional issues raised in connection with administrative enforcement proceedings, including the use of ALJs to adjudicate cases, see Geoffrey F. Aronow, Back to the Future: The Use of Administrative Proceedings at the CFTC and SEC, 35 Futures and Derivatives L. Rep. 1 (Jan./Feb. 2015). 11. CEA §6(c)(4), 7 U.S.C. §9(4) (2014). 12. CEA §6(c)(10), 7 U.S.C. §9(10) (2014). 13. 17 C.F.R. §10.21. 14. 17 C.F.R. §10.22(a). The complaint also must notify the respondent of its right to a hearing and specify the time required under Regulation 10.23 for filing an answer. Regulation 10.22 also specifies the manner of service of process for the complaint. Regulation 10.12 specifies the service and filing requirements for filings subsequent to the complaint. 15. A statement of lack of information has the same effect as a denial; any allegation not expressly denied shall be deemed to be admitted. 17 C.F.R. §10.23(b)(1). 16. 17 C.F.R. § 10.23(b)(2). 17. 17 C.F.R. §10.23(c). © 2015 THOMSON REUTERS March 2015 18. 19. 20. 21. 22. 23. 24. 25. 26. 27. 28. 29. 30. 31. 32. n Volume 35 n Issue 2 17 C.F.R. § 12.26(c) (2009); CFTC, President’s Budget and Performance Plan, Fiscal Year 2013 60 (Feb. 2012). Id. 17 C.F.R. § 10.8. 17 C.F.R. § 10.9(a) 17 C.F.R. § 10.9(b). This prohibition does not apply to the members of the Commission. 17 C.F.R. § 10.10. Similarly, a Commissioner, ALJ, or other Commission employee involved in the decisional process may not make to any interested person outside the Commission an ex parte communication that is relevant to the merits of the proceeding. Regulation 10.10 also specifies procedures for the handling of ex parte communications, including providing notice to all parties in the proceeding, placing the communication in the public record of the proceeding, and potential sanctions for knowing violations of the prohibition. 17 C.F.R. § 10.41. Any person whose interests may be affected substantially by the proceeding may petition the ALJ to intervene as a party to the proceeding. To grant a petition to intervene as a party the ALJ must determine: (1) a substantial interest of the person seeking to intervene may be adversely affected by the proceeding; (2) the intervention will not materially prejudice the rights of any party; (3) participation as a party is otherwise consistent with the public interest; and (4) that leave to be heard would be inadequate to protect the person’s interest. 17 C.F.R. § 10.33. 17 C.F.R. § 10.42(a)(1). A party must also provide any such documents, data, or other written information that the other parties do not already have in their possession and to which they do not have reasonably ready access 17 C.F.R. § 10.42(a)(2). These procedures in Regulations 10.42(a)(1) and 10.42(a)(2) are not applicable to rebuttal evidence. 17 C.F.R. § 10.42(a)(3). 17 C.F.R. § 10.42(b)(1). The Division may also withhold information obtained from a domestic or foreign governmental entity or from a foreign futures authority that is either not relevant to the proceeding or that was provided on the condition that it not be disclosed or that it be disclosed only by the Commission or a representative of the Commission as evidence in an enforcement or other proceeding. 17 C.F.R. § 10.42(b)(2). 17 C.F.R. § 10.42(b)(3). 17 C.F.R. § 10.42(c). The Division’s obligations to produce witness statements under Rule 10.42(c) “generally accords with Rule 26.2 of the Federal Rules of Criminal Procedure, which 11 March 2015 33. 34. 35. 36. 37. 38. 39. 40. 41. 42. 43. 44. 45. 46. 47. 12 n Volume 35 n Issue 2 places in the Federal Rules the substance of the Jenks Act, 18 U.S.C. 3500.” Rules of Practice, 63 Fed. Reg. 55784, 55787 (Oct. 19, 1988). Under “the rule set forth in Jencks v. United States, 353 U.S. 657 (1957) and codified in 18 U.S.C. § 3500 (1994) … a criminal defendant ‘is entitled to relevant and competent reports and statements in possession of the Government touching the events and activities as to which a Government witness has testified at the trial.’ First Guaranty, [1980-1982 Transfer Binder] P 27,258 at 46,102.” In the Matter of Schiller and Chesrow, Comm. Fut. L. Rep. (CCH) P29,141, (CFTC, Sept. 3, 2002). 17 C.F.R. § 10.42(f). The Commission’s Rule 10.42(f) is modeled after Federal Rule of Civil Procedure 26(a)(3)(C). Rules of Practice, supra, at 55,787. 17 C.F.R. § 10.44(a). The application must include: (1) the name and address of the witness; (2) the specific matters concerning which the witness is expected to testify and their relevance; (3) the reasons why the deposition should be taken, supported by affidavits and a physician’s certificate, where appropriate; (4) the time when, the place where, and the person before whom the deposition will be taken; (5) a specification of the documents any materials which the deponent is expected to produce; and (6) application for any subpoena.. 17 C.F.R. § 10.44(b). 17 C.F.R. § 10.44(f)-(g) (2014); In the Matter of Global Minerals & Metals Corp., et al., Comm. Fut. L. Rep. (CCH) P29,555 (CFTC, Aug. 4, 2003). 17 C.F.R. § 10.68(a). The requesting party must show the general relevance of the testimony or evidence being sought. 17 C.F.R. § 10.68(c). In determining whether to grant a protective order, the ALJ “shall weigh the harm resulting from disclosure against the benefits of disclosure.” CEA §§ 6(c)(5)-(9), 7 U.S.C. §§ 9(5)-(9) (2014). 17 C.F.R. § 10.44(e), (f). 17 C.F.R. § 10.42(e). 17 C.F.R. § 10.66 (b). Id. 17 C.F.R. § 10.66(c). In re Reddy, Comm. Fut. L. Rep. (CCH) P27,271 (CFTC, Feb. 4, 1998), quoted approvingly in In the Matter of Anthony J. DiPlacido, supra note 5. In Reddy, the Commission also stated, “a party is guaranteed only ‘an opportunity for effective cross-examination,’ and the trier of fact may properly exercise discretion to impose reasonable limits on the scope of cross-examination.” (additional citations omitted). 17 C.F.R. § 10.67(a). In the Matter of Anthony J. DiPlacido, supra note 6. Futures & Derivatives Law Report 48. 49. 50. 51. 52. 53. In the Matter of Zuccarelli, Comm. Fut. L. Rep. (CCH) P27,597 (CFTC, Apr. 15, 1999) (“With respect to the opinion of a lay witness, we are guided by Federal Rule of Evidence 701 … .”). Rule 701 provides: “If the witness is not testifying as an expert, the witness’ testimony in the form of opinions or inferences is limited to those opinions or inferences which are (a) rationally based on the perception of the witness and (b) helpful to a clear understanding of the witness’ testimony or the determination of a fact in issue.” In the Matter of Brian W. Ray, Comm. Fut. L. Rep. (CCH) P41,914 (CFTC, Feb 18, 2011) (“As an administrative agency, the Commission is not bound by the Federal Rules of Evidence as to the admissibility of expert witnesses … Nevertheless, the Commission has considered those rules for guidance in determining whether certain evidence is admissible… . Under those rules, expert testimony must be both reliable and relevant. To be reliable, ‘ the reasoning or methodology underlying the testimony [must be] scientifically valid.’ Daubert v. Merrell Dow Pharmaceuticals, Inc., 509 U.S. 579, 5923 (1993). To be relevant, the evidence must be applicable ‘to the facts in issue.’ Id. at 593.”). See also In re Ashman, Comm. Fut. L. Rep. (CCH) P27,336 (CFTC, Apr. 22, 1998) (citing Fed. R. Evid. 702 and stating expert witness testimony is permitted when it “will assist the trier of fact to understand the evidence or to determine a fact in issue”). In the Matter of First Guaranty Metals, Comm. Fut. L. Rep. (CCH) P21,074 (CFTC, Jul. 2, 1980). In First Guaranty Metals, the Commission explained that the Brady rule “is not a discovery rule rather it is a rule of fairness and minimum prosecutorial obligation” and therefore a matter of due process. See also In the Matter of Bilello, Comm. Fut. L. Rep. (CCH) P27,345 (CFTC, Apr. 23, 1998); Brady v. Maryland, 373 U.S. 83 (1963). Although the Supreme Court has not ruled on whether the Brady rule applies to civil cases, Demjanjuk v. Petrovsky, 10 F.3d 338, 353 (6th Cir. 1993), four other federal agencies—the SEC, the Federal Maritime Commission, the Federal Deposit Insurance Commission, and the Federal Energy Regulatory Commission—also follow the Brady rule, although not in an identical manner. See Note, Hold Fast the Keys to the Kingdom: Federal Administrative Agencies and the Need for Brady Disclosure, 95 Minn. L. Rev. 1424, 1425 (2011). 17 C.F.R. § 10.101. See, e.g., In the Matter of Global Minerals & Metals Corp., Comm. Fut. L. Rep. (CCH) P28,655 (CFTC, Oct. 3, 2001). 17 C.F.R. § 10.101(a)(1)-(4). 17 C.F.R. § 10.101(a)(5). © 2015 THOMSON REUTERS Futures & Derivatives Law Report 54. 55. 56. 57. 58. 59. 60. 61. 62. 63. 64. 65. 66. 67. 68. 69. 70. 71. 72. 17 C.F.R. § 10.84. In the Matter of Ray, Comm. Fut. L. Rep. (CCH) P31, 914 (CFTC, Feb. 18, 2011); see also In the Matter of Mayer, Comm. Fut. L. Rep. (CCH) P28, 935 (CFTC, Feb. 28, 1998). In the Matter of Ray, supra (“in applying the weight or preponderance of the evidence standard … “); see also Reddy v. CFTC, 191 F.3d 109, 117 (2d Cir. 1999) (“However, our role in reviewing the Commission finding of preponderance is narrow.”). 17 C.F.R. § 10.102. Notice of appeal must be filed within 15 days after service of the initial decision or other order terminating the proceeding. Regulation 10.102 also specifies the procedures and requirements for filing crossappeals and briefs. In determining to permit cross-appeals by either party, the Commission noted that cross appeals have long been permitted under Federal Rule of Appellate Procedure 4(a)(3) “with no apparent abridgement of any party’s right to due process.” Rules of Practice, supra note 32, at 53,790. 17 C.F.R. § 10.105. 17 C.F.R. § 10.104(a). In the Matter of Grossfeld, Comm. Fut. L. Rep. (CCH) P26,921 (CFTC, Dec. 10, 1996). 17 C.F.R. § 10.103. Interviews with former Commission staff indicate that the Commission last held an oral argument in the late 1990s. 17 C.F.R. § 10.84(c)(2). CEA § 6(c)(11), 7 U.S.C. § 9(11) (2014). Timely appeal of an initial decision by an ALJ to the Commission is “mandatory as a prerequisite to seeking judicial review” of any final decision. 17 C.F.R. § 10.102(f). P.L. 93-463, Commodity Futures Trading Commission Act of 1974. P.L. 102-546, Futures Trading Practices Act of 1992, Sec. 221. 170 F.2d 220 (7th Cir. 1948) 201 F.2d 476 (7th Cir. 1953). 311 F.2d 52 (5th Cir. 1962). 452 F.2d 1154 (8th Cir. 1971). General Foods Corp. v. Brannan, 170 F.2d 220 (7th Cir. 1948). “The Seventh Circuit’s decision in this case did not sit well with the government, who viewed it as allowing price stabilizing and pegging of prices through futures trades in order to protect the price of a cash position.” Jerry W. Markham, Law Enforcement and the History of Financial Market Manipulation 102 (M.E. Sharpe, 2014). 311 F.2d at 59. See generally Jerry W. Markham, Manipulation of Commodity Futures Prices—The Unprosecutable Crime, 8 Yale Journal on Regulation 281, 352-358 (1991). At the time, commenters viewed the agency’s use of administrative en- © 2015 THOMSON REUTERS March 2015 73. 74. 75. 76. 77. 78. 79. 80. n Volume 35 n Issue 2 forcement process positively: “It is within the context of its own administrative enforcement and disciplinary proceedings, however, that the Commission is able to best articulate its jurisdictional and legislative philosophy and to exhibit to the professional community and investing public its ability to policy the commodity industry.” Michael S. Sackheim, Administrative Enforcement of the Federal Commodities Laws by the Commodity Futures Trading Commission, 12 Seton Hall L. Rev. 445, 447 (1982) (citations omitted). In the Matter of Hohenberg Bros., Comm. Fut. L. Rep. (CCH) P20,271 (CFTC, Feb. 18, 1977). The Commission concluded, however, that the evidence before it did not support a finding of attempted manipulation and dismissed the complaint. Id. In the Matter of Indiana Farm Bureau Coop. Ass’n, Comm. Fut. L. Rep. (CCH) P21,796 (CFTC, Dec. 17, 1982). Id. The Commission also dismissed the complaint. “This holding appeared to signal that the CFTC was adopting, and even extending, the Volkart decision that the CEA had sought to overturn by legislation.” Markham, The Unprosecutable Crime, supra note 72, at 189. The Commission also found the Division had not met its burden of proof and dismissed the complaint. In the Matter of Cox, Comm. Fut. L. Rep. (CCH) P23,786 (CFTC, July 15, 1987). Professor Markham termed the Cox case a “regulatory disaster,” Markham, History of Manipulation, supra note 70, at 191, and has argued that the CFTC, through its interpretations, “effectively nullified the manipulation prohibition.” Markham, The Unprosecutable Crime, supra note 72, at 285. See, e.g., CFTC v. Wilson, 13 Civ 7884 (S.D.N.Y. filed Nov. 6, 2013) (complaint alleging manipulation and attempted manipulation of threemonth interest rate swap futures contracts); CFTC v. Optiver, 08-CIV 6560 (S.D.N.Y. complaint filed July 24, 2008, final consent order filed April 19, 2012) (complaint alleging manipulation of the settlement price of crude oil, heating oil, and gasoline futures contracts); CFTC v. Parnon Energy, Arcadia Petroleum Ltd. And Arcadia Energy (Suisse) , 11 Civ. 3543 (S.D.N.Y. complaint filed May 24 2011; final consent order filed August 4, 2014) (complaint alleging manipulation and attempted manipulation of the price of crude oil futures contract spreads). U.S. General Accounting Office, Administrative Law Judges, Comparison of SEC and CFTC Programs, GAO/GGD-96-27 (Nov. 1995). During this period ALJs issued 46 initial decisions and the Commission ruled on 48 appeals of ALJ decisions. In 14 of these cases the Commission 13 March 2015 81. 82. 83. 84. 85. 86. 87. 14 n Volume 35 n Issue 2 reduced the sanction imposed by the ALJ, and in 4 of the appeals the Commission increased the sanction. Only one of the cases reviewed by GAO during this period involved manipulation. Id. In the Matter of Abrams, Comm. Fut. L. Rep. (CCH) P26,479 (CFTC, Jul. 31, 1995). Following the Commission’s dismissal of the complaint in Cox, one of the targets of the Commission’s investigation, George Frey, filed a request for attorney’s fees under the Equal Access to Justice Act. In 1991, the court dismissed Frey’s appeal of the Commission’s denial of attorney’s fees, finally concluding the case slightly more than 20 years after the conduct at issue occurred. Frey v. CFTC, 931 F.2d 1171 (7th Cir. 1991). Professor Markham notably has concluded that the Commission’s adjudicatory decisions in manipulation cases was a major reason for its difficulty in successfully prosecuting manipulation, “The small number of cases brought and the very small number of respondents who have been subject to significant sanctions, particularly in contested cases, suggest that manipulation is virtually an unprosecutable crime. This is due to the difficulty of meeting the standards of manipulation articulated by the CFTC.” Markham, The Unprosecutable Crime, supra note 72, at 356. Silverman v. CFTC, 549 F.2d 28 (7th Cir. 1977). Id. at 33 (internal citations omitted). Id. Gimbel v. CFTC, 872 F.2d 196 (2d Cir. 1989). Similarly, the Second Circuit has stated that “fundamental fairness requires a fair trial in a fair tribunal … with fair notice of the matters at issue and an opportunity to cross-examine witnesses.” Piccolo v. CFTC, 388 F.3d 387, 391 (2d Cir. 2004) (upholding Commission Order summarily affirming Exchange disciplinary action against trader for throwing first punch in brawl outside Exchange). Graham v. CFTC, 1988 U.S. App. LEXIS 22152 (9th Cir. 1988), quoting Chapman v. CFTC, 788 F.2d 408, 419 (7th Cir. 1986). See also McClelland v. Andrus, 606 F.2d 1278, 1285 (D.C. Cir. 1979) (“The extent of discovery that a party engaged in an administrative hearing is entitled to is primarily determined by the particular agency; both the Federal Rules of Civil Procedure and the Federal Rules of Criminal Procedure are inapplicable and the Administrative Procedure Act fails to provide expressly for discovery; further courts have consistently held that agencies Futures & Derivatives Law Report 88. 89. 90. 91. 92. 93. 94. 95. 96. 97. 98. 99. 100. 101. 102. 103. 104. 105. 106. need not observe all the rules and formalities applicable to courtroom proceedings.”). Lloyd Carr & Co. v. CFTC, 567 F.2d 1193 (2d Cir. 1977). Id. at 1196 (citation omitted). Id. at 1197. The Commission had argued that any evidence that would have been produced would not have affected the outcome. 7 U.S.C. § 9 (2008). Reddy v. CFTC, 191 F.3d 109, 114 (2d Cir. 1999). See also Haltmier v. CFTC, 554 F.2d 556, 560 (2d Cir. 1977) (“The ‘weight of evidence’ means ‘the preponderance’ or ‘greater weight of the evidence’” (citation omitted)). Great Western Foods, supra note 67, at 479-80; Reddy, supra; Haltmier, supra; Silverman, supra note 83. 5 U.S.C. §706(E). Airport Shuttle Service, Inc., v. Interstate Commerce Comm’n, 676 F.2d 836, 840 (D.C. Cir. 1982); see also , McHenry v. Bond, 668 F.2d 1185, 1190 (11th Cir. 1982) (“It is something more than a scintilla of evidence, but something less than the weight of the evidence.”). See note 93 and accompanying text, supra, quoting Chevron, U.S.A., Inc. v. Natural Res. Defense Council, 467 U.S. 837, 844 (1984). Monieson v. CFTC, 996 F.2d 852, 858 (7th Cir. 1993). Reddy v. CFTC, 191 F.3d 109, 124 (2d Cir. 1999), quoting Motor Vehicle Mfrs. Ass’n v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983) and Burlington Truck Lines v. United States, 371 U.S. 156, 168 (1962); see also DiPlacido v. CFTC, 364 Fed. Appx., 657 (2d Cir. 2009). . DiPlacido, supra, at 661. In Cargill v. Hardin, supra note 69, the defendant argued that the CEA’s “weight of the evidence” standard was “considerably more stringent” than the APA’s “substantial evidence” test. In response, the Eighth Circuit endorsed the standard of review set forth by the Seventh Circuit in General Foods Corp. v. Brannan.; see also Wilson v. CFTC, 322 F.3d 555 (8th Cir. 2003). Elliott v. CFTC, 202 F.3d 926 (7th Cir. 2000). Id., at 932. Id., at 940, Easterbrook, J. dissenting. Chau v. SEC, ___F. Supp.3d ___(S.D.N.Y.) 2014 WL 6984236. Id. Whitman v. U.S., 574 U.S. ___ (2014) (denial of petition for writ of certiorari, Scalia, J. dissenting) Id. © 2015 THOMSON REUTERS From: To: Subject: Date: Attachments: Beth L. Soliere Bob Stump FW: HEPG Carbon panel advance materials Wednesday, December 07, 2016 1:56:58 PM The Great Swap Nov 2016.pdf I did receive this. I will email Jo-Ann.   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Monday, December 05, 2016 9:55 AM To: Mahoney, Jo-Ann Cc: Gill, Susan Subject: HEPG Carbon panel advance materials   In anticipation of Friday’s panel on carbon policy at the HEPG Arizona meeting, we are distributing a paper by Harvard Kennedy School professor Joseph Aldy, on “The Great Swap.”  We are also including “A Practical Guide to the Economics of Carbon (Dioxide) Pricing” by panelist Ross MicKitrick.     http://www.policyschool.ca/wp-content/uploads/2016/02/Carbon-Pricing-McKitrickFINAL.pdf A Practical Guide to the Economics of Carbon (Dioxide) Pricing www.policyschool.ca another important rule for creating a proper carbon-pricing system is to be as careful as possible in estimating the social cost of carbon. Estimates are all we have ...   From: Mahoney, Jo-Ann Sent: Monday, November 21, 2016 8:34:05 AM To: Ross McKitrick Subject: HEPG Speaker Logistics   Dear Ross, Thank you for agreeing to participate as a speaker at the upcoming HEPG session in Scottsdale, Arizona. Your panel is scheduled for Friday morning, December 9. Speakers are welcome to attend the entire conference as well as the reception and dinner on Thursday evening, as your schedule permits. Here are a few logistical details. 1) The conference will take place at the Four Seasons Troon North in Scottsdale. We are making a reservation for you. Please let me know asap if you require lodging for Wednesday and Thursday evening, December 7 and 8 or only Thursday evening. (I know that you are booking airfare directly through Harvard Travel; if you should need any further assistance, do not hesitate to ask.) 2) If you have any materials you would like distributed in advance of the meeting -- to inform the discussion, send them to me. 3) Please let us know if you plan to use a powerpoint presentation. We plan to distribute slides at the meeting, and would prefer to have an electronic copy by Friday, December 2. I look forward to meeting you in Arizona. Regards, Jo-Ann Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group (HEPG) Harvard Kennedy School 79 JFK Street Cambridge, MA LONG-TERM CARBON POLICY: THE GREAT SWAP Long-term Carbon Policy: The Great Swap Joseph E. Aldy November 2016 P1 About the Author Joseph E. Aldy is an Associate Professor of Public Policy at the Harvard Kennedy School, a Visiting Fellow at Resources for the Future, a Faculty Research Fellow at the National Bureau of Economic Research, and a Senior Adviser at the Center for Strategic and International Studies. His research focuses on climate change policy, energy policy, and mortality risk valuation. He also serves as the Faculty Chair of the Mossavar-Rahmani Center for Business and Government Regulatory Policy Program. In 2009-2010, he served as the Special Assistant to the President for Energy and Environment at the White House. Aldy previously served as a Fellow at Resources for the Future, Co-Director of the Harvard Project on International Climate Agreements, Co-Director of the International Energy Workshop, and worked on the staff of the President's Council of Economic Advisers. He earned his doctorate in economics from Harvard University and MEM and bachelor degrees from Duke University. LONG-TERM CARBON POLICY: THE GREAT SWAP Contents THE POLITICAL CHALLENGE OF CLIMATE POLICY 4 THE GREAT SWAP 6 THE POLITICAL SUPPORT FOR THE GREAT SWAP 7 THE CASE FOR AN ECONOMY-WIDE CARBON TAX 13 CARBON PRICE CERTAINTY 14 HOW TO DESIGN A CARBON TAX 25 HOW TO USE THE CARBON TAX REVENUES 32 CONCLUSION 34 P3 LONG-TERM CARBON POLICY: THE GREAT SWAP Long-term Carbon Policy: NOVEMBER 2016 Joseph E. Aldy The Great Swap THE POLITICAL CHALLENGE OF CLIMATE POLICY their greenhouse gas emissions. Now, the election of Donald J. Trump, an avowed global warming skeptic, has thrown America’s commitment to global leadership in doubt. If the United States quits the fight against climate change, this risks unraveling the global coalition and could result in other countries following suit. This would be a tragic mistake with incalculable consequences for the entire planet. Moreover, some nations may retaliate against the United States by imposing tariffs on Americanmanufactured goods based on the greenhouse gas emissions associated with their production. In the past two decdes, the mounting risks posed by climate change have motivated businesses, cities, states, national governments, and the international community to pledge to take action to reduce their greenhouse gas emissions. Given the scale of the problem, the breadth of action must be effective and must set the foundation for increasing mitigation efforts over time. Thus, delivering on these pledges will require effective policies to drive the deployment of low-carbon technologies today and technological innovation in the future to ramp ambition up on par with the risks of climate change. If, on the other hand, President Trump is willing to use his vaunted powers as a dealmaker, there are real possibilities for breaking the present impasse in Washington over energy and climate policy. Not so long ago, there was bipartisan support for the proposition that the United States must do its part to slow down the heating of the Earth’s atmosphere. At the Rio de Janeiro Earth Summit in 1992, President George H. W. Bush signed the global climate treaty, which Climate change is a problem no country can solve by itself. Since the mid-1990s, the United States has advocated for developed and developing countries to work together in combating climate change and, with the United States’ leadership, the 2015 Paris Agreement delivered unprecedented commitments by virtually every country on the planet to reduce P4 LONG-TERM CARBON POLICY: THE GREAT SWAP the Senate ratified unanimously later that year. In the 2008 presidential campaign, Senators McCain and Obama supported virtually identical economy-wide greenhouse gas cap-and-trade programs with ambitious targets through 2050. Since then, Republicans have actively opposed climate policy, with only six Republican members voting for the 2009 Waxman-Markey energy and climate bill. In the wake of failed capand-trade legislation, the Obama Administration advanced regulations – the Clean Power Plan, fuel economy standards, appliance efficiency standards – as well as administrative initiatives to address climate change. In addition, a number of states have promoted more aggressive climate change and renewable power policies over the past decade. each country pledges voluntary contributions to the global effort to combat climate change and a focus on transparency in implementation to assess whether all major partners undertake comparable efforts. Even if the Paris Agreement is not a first-tier priority of the incoming administration, the fact that it is a top priority for many countries around the world provides a potential leverage point for the United States in other bilateral or multilateral negotiating contexts. Since the climate agreement is part of a much more complex web of international relations, the U.S. engagement in it can facilitate efforts to secure deals on the incoming Some states and industries have taken the lead on climate policy, implementing carbon pricing policies and deploying wind, solar, and energy efficiency technologies. The President-elect has stated his intention to reverse a number of these regulations, including the Clean Power Plan. Just as opponents of the Clean Power Plan have used the courts to slow and potentially halt its implementation, the proponents of the Clean Power Plan will use the courts to slow efforts to reverse it. Given the statutory requirements on regulatory decisionmaking, an agency cannot simply change its mind on a regulation without making its case and subjecting this to public comment. This legal uncertainty coupled with the continuing patchwork of state policies – including capand–trade programs covering power-sector carbon dioxide emissions in states representing 25 percent of the U.S. population – makes for an unpredictable investment climate for the utility sector. administration’s foreign policy priorities. Walking away from the Paris Agreement would make it much more difficult for the incoming administration to work with other countries on issues ranging from terrorism, to trade, to cybersecurity, to public health and pandemics, as well as an array of bilateral issues. A smart deal to tackle climate change could abet tax and regulatory reform – which most Republicans support – by swapping a marketbased carbon tax for sectoral regulatory policies – which most Republicans oppose. Such an approach could make even greater reductions in tax rates politically feasible and demonstrate that Republicans are in favor of smarter environmental policy, not simply opposed to all Reversing existing climate change policies also raises questions about the U.S. commitment to the Paris Agreement. The key elements of the Paris Agreement represent long-standing U.S. interests – a respect for sovereignty in how P5 LONG-TERM CARBON POLICY: THE GREAT SWAP climate change policies. This report describes how that deal would work. ways of cutting emissions, a carbon tax can be quite effective environmentally. A transparent, administratively simple policy approach, a carbon tax represents good public policy in a democracy. Finally, an economy-wide carbon tax would enable U.S. negotiators to demonstrate continued U.S. leadership on climate policy and signal a seriousness that would elicit reciprocal policies and actions among our partners participating in multilateral climate policy. An illustration of a carbon tax is presented in the box on the following page and elaborated further in the carbon tax design section below. THE GREAT SWAP A “Great Swap” – a carbon tax and regulatory streamlining as a part of tax reform – can navigate these political challenges and serve as a credible way forward for the United States on climate policy. The Benefits of a Carbon Tax A carbon tax can drive the deployment of technologies and innovation necessary to cut greenhouse gas emissions and combat climate change risks. And, by getting the biggest climate bang for the buck, a carbon tax makes the politics and economics of driving down emissions easier. Imposing the same carbon price on all sources of emissions is not only cost-effective, but fair in the sense that everyone who pollutes must bear the same cost for their pollution. By creating a strong profit incentive for businesses to seek out and exploit low-cost Enabling Tax Reform An economy-wide carbon tax would produce substantial revenues – as much as several hundred billion dollars annually – that could finance significant reductions in existing tax rates on personal and corporate income. Indeed, a meaningful tax reform package will need to tap new revenue sources to deliver lower tax rates without increasing federal deficits. The rationale P6 LONG-TERM CARBON POLICY: THE GREAT SWAP for coupling a carbon tax and tax reform are twofold. First, the climate policy and tax reform benefit from each other in terms of economics. Tax reform lowers the costs to the economy -- and potentially eliminates the net costs -- of a carbon tax, while the carbon tax provides the revenues to finance the tax reform. Second, such an approach can neutralize the difficult politics that characterize each issue by broadening the political coalition that would derive a “win” from at least some element of the policy package. Such a broad coalition would ensure the durability of the carbon tax and tax reform, and is consistent with major policy efforts in the past that have coupled policy initiatives to draw broader support, such as under the regular farm bill and transportation bill processes. comprehensive, durable policy instruments to drive a low-carbon economy. POLITICAL SUPPORT FOR THE GREAT SWAP What Republicans Could Gain from the Great Swap A carbon tax in the context of a revenue-neutral tax reform could elicit Republican support. The Republicans will have a primary objective of lowering tax rates in a tax reform, subject to the constraint that the tax reform would not increase the federal deficit. As a result, substantial tax reform that lowers tax rates can only satisfy this political constraint if it also secures meaningful revenues raisers. A carbon tax generating $100 billion to $200 billion annually in revenues could enable larger rate cuts, which would likely serve as the most important marker of policy success to key stakeholders in the Republican Party. The Benefits of Regulatory Streamlining A carbon tax could substitute for the rigid and complicated framework of command and control regulations that define the status quo. The absence of a comprehensive, national climate policy has produced a vacuum. It has required a vast array of legislative changes at the state level to ramp up renewables. It has required new tax bills every year or two to continue support for renewables. The regulatory approach under the Clean Air Act will take years to surmount the political and legal hurdles, only to cover one (albeit important) industry. Then the process starts over with another industry. Likewise, appliance efficiency standards are one-by-one. And none of these policies – the Clean Air Act, tax credits, fuel economy standards, appliance standards, or state Renewable Portfolio Standards – envision more ambitious reductions after 2030 (or post-2025 in some cases). This complicated suite of policies is not the path to a low-carbon economy; it is a collection of stopgap measures waiting for more A number of conservative and Republican thought leaders have advocated for a revenueneutral carbon tax. Arthur Laffer, whose work has informed much of Republican tax policy since the 1980s, and former Representative Bob Inglis (R-SC) wrote in the New York Times that “fiscal conservatives would gladly trade a carbon tax for a reduction in payroll or income taxes, but we can’t go along with an overall tax increase.” George Shultz, who served as Secretary of the Treasury and State in Republican administrations, and Nobel laureate Gary Becker advocated for a carbon tax in the Wall Street Journal on the condition of revenue neutrality, since this would “mean that it will not have a fiscal drag on economic growth.” The prospect of replacing a complicated mix of regulations with a carbon tax also appeals to conservative thought leaders. In the Weekly Standard, Irwin Stelzer of the Hudson Institute (and formerly the American Enterprise Institute) P7 LONG-TERM CARBON POLICY: THE GREAT SWAP called for a carbon tax to finance a reduction in the payroll tax, noting that “it gives conservatives a market-based tool to replace regulations and relieves them of a need to sign on to the climate change thesis by providing a true, conservative rationale – consumption taxes that ease the burden of taxation on work are pro-growth.” Greg Mankiw, former Chair of the Council of Economic Advisers in the George W. Bush Administration, called for a carbon tax as a lower cost way to reduce emissions than a collection of regulations and stated in the New York Times that “using the new revenue to reduce personal and corporate income tax rates, a bipartisan compromise is possible to imagine.” sector alone, utilities and electricity consumers face a large set of overlapping policies, such as state renewable mandates, energy efficiency mandates on utilities, appliance efficiency mandates, tax credits for renewable power, accelerated depreciation for renewable power, the Clean Power Plan, net metering, energyefficient appliance rebates, state and regional carbon dioxide cap-and-trade programs, etc. Consider that, in the transportation sector in California, the gasoline a consumer purchases is subject to a state low-carbon fuel standard, a state carbon dioxide cap-and-trade program, Many in the environmental community have worked hard to advance the Clean Power Plan and, despite its legal uncertainty, they may be reluctant to support a policy that would remove the Clean Air Act as a policy tool. The prospect of a bipartisan agreement still must overcome significant political hurdles. The House of Representatives voted for a resolution in June 2016 – almost completely along party lines – that expresses the sense that a carbon tax would be “detrimental to the U.S. economy.” Given the text of the resolution and its political context, it would seem politically infeasible to advance a standalone carbon tax bill in a Republican-controlled House of Representatives. The silence of the resolution, however, on using a carbon tax to cut tax rates and to replace a complicated regulatory regime suggests that a Great Swap could receive serious consideration. a national renewable fuel standard (with carbon performance benchmarks) and, when put into a car manufactured under fuel economy standards, a tailpipe carbon dioxide standard, and a zero emissions vehicle mandate. It is well known within the environmental community that the set of regulatory tools available under current law are not sufficiently powerful to deliver on long-term emission goals, and may not be enough to reach the Paris Agreement goal of 26 to 28 percent below 2005 levels by 2025. Several environmental groups have issued analyses that, while optimistic about the prospects of new policies to deliver on the 2025 goal, clearly recognize that the current set of policies, subsidies, and regulations in place – including the Clean Power Plan, which could be weakened through judicial review – will not deliver a 26 percent reduction in emissions Why Progressives Would Support the Great Swap The United States is not starting from scratch with climate policy. While carbon pricing legislation has been under consideration in the Congress since at least 2003, the absence of legislative progress has resulted in the use of existing statutory authorities to address climate change. The status quo is complicated, redundant and costly and doesn’t deliver the emissions reductions we need. In just the power P8 LONG-TERM CARBON POLICY: THE GREAT SWAP Using a carbon tax to cut tax rates and `replace a complicated regulatory regime suggests that a Great Swap could receive serious consideration in a Republican-controlled House of Representatives. P9 LONG-TERM CARBON POLICY: THE GREAT SWAP by 2025. requires a product-by-product and/or industryby-industry series of regulations, each of which would then involve periodic updating through new rule-makings. The vagaries of the rulemaking process, as well as potential legal and legislative challenges, prevent firms from forming sensible expectations about the form and stringency of future climate regulations. The certainty of long-term U.S. climate policy through a carbon tax could also remove a barrier to business investment generally, as some firms have hedged capital outlays and R&D investments pending resolution of climate policy. As Bob Dudley, the CEO of BP, noted last year, “a global carbon price would help to unleash market forces and provide the right incentives for everyone to play their part.” This is the very reason leaders in the environmental community worked intensively for long-term, economy-wide cap-and-trade legislation in 2009 and 2010. There are political risks with swapping a carbon tax for these regulatory policies and subsidies, since there are vested interests associated with the status quo. Many in the environmental community have worked hard to advance the Clean Power Plan and, despite its legal uncertainty, they may be reluctant to support a policy that would remove the Clean Air Act as a policy tool. Having said that, there may be those in the business community who would not support a carbon tax without regulatory streamlining. Second, many businesses that would have to either comply with greenhouse gas regulations Moreover, the prospect of lowering tax burdens on the middle-income and lower-income households could be quite appealing to many progressives. Delivering a tax reform that improves the progressivity of the tax code – as well as its efficiency – could serve as a way to promote economic growth and address income inequality. The opportunity to improve the progressivity of the tax code and establish a meaningful, long-term, economy-wide driver of emission reductions would likely outweigh reservations about pre-empting statutory authorities under the Clean Air Act that are still pending judicial review. The uncertainty about potentially irreversible changes to the global climate provides a strong case for taking action to reduce the prospect and magnitude of adverse climate change. or a carbon tax would prefer the carbon tax as a less costly and more effective policy approach. For example, the vice president of public and government affairs for Exxon Mobil recently wrote in the Dallas Morning News that “of the policy options being considered by governments, we believe a revenue-neutral carbon tax is the best.” Why Business Would Support the Great Swap The vast majority of the business community would find the Great Swap a strongly compelling alternative to the status quo. First, an economywide carbon tax would provide substantially more certainty than the current regulatory approach. In contrast to a carbon price, the complicated mix of regulatory instruments Third, a carbon tax would significantly ease the administrative burden for many businesses, P10 LONG-TERM CARBON POLICY: THE GREAT SWAP relative to compliance efforts under existing regulations. Many businesses already track their carbon dioxide emissions, either under EPA reporting requirements or voluntarily through such efforts as the Carbon Disclosure Project. Thus, businesses can readily assess how a carbon tax would affect the costs of their operations, in contrast to the uncertainty and complexity of regulations. Those businesses with the statutory obligation of paying the carbon tax could use their existing emissions accounting as the basis for estimating their tax payments. power plants. Firms and investors active in the clean energy space would benefit from a longterm policy signal, in contrast to the uncertainty associated with periodic tax extenders bills – which subsidize these technologies over short periods of time – and future regulations. Why Labor Would Support the Great Swap The labor community has, with some notable exceptions, supported policies that promote clean energy investment and combat climate change. For example, the demand for manufactured inputs in wind and solar power facilities translated into demand for unionized workers, such as the United Steelworkers, who supported the 2009 Waxman-Markey cap-andtrade bill. A carbon tax would provide long-term demand for such inputs, and could finance a lower payroll tax-both of which would receive the support from labor. Fourth, a carbon tax that finances a lower corporate income tax rate would also appeal to Large American corporations, including manufacturers such as Colgate-Palmolive, General Motors, and Owens Corning; electric utilities such as AEP, Duke Energy, Exelon, and NRG Energy; oil companies, such as ConocoPhillips and Exxon Mobil; and, information technology companies, such as Google and Microsoft all employ carbon prices in internal planning ranging from $5/tCO2 to $85/tCO2. The challenge with the labor community lies with workers in two sectors, whose concerns cannot be addressed under the current regulatory approach to climate change. First, coal workers have a legitimate concern that climate policy will reduce demand for coal and hence lead to mine closings and layoffs. There are virtually no tools to address these concerns under current law. A carbon tax could finance a coal community fund that could enable coal workers to transition to new employment. many businesses. Depending on the level of the carbon tax and the magnitude of the corporate tax rate cut, a majority of businesses could pay less in taxes to the federal government under the Great Swap than they do under the current tax code. Greenhouse gas regulations under the Clean Air Act cannot raise federal revenues, nor does the law permit the use of revenues for aiding coal communities. Thus, a policy package of a carbon tax with a coal community program could be a more appealing alternative to the current (and future) regulations under existing statutory authority. Finally, an economy-wide carbon tax could also create more demand for long-lived energy technologies, such as wind, solar, and nuclear Second, labor in energy-intensive industries P11 LONG-TERM CARBON POLICY: THE GREAT SWAP Steps Toward an Economy-Wide Carbon Tax • Enact a tax on the carbon content of all fossil fuels in the U.S. economy. • Use revenues from the carbon tax to finance comprehensive tax reform, including potential reductions in the corporate and personal income tax rates. Some revenues could finance a cash assistance program that targets low-income households whose taxes may be primarily in the form of payroll and/ or sales taxes. In addition, some revenues could be set aside for assistance to coal communities and other communities and industries adversely affected by climate policy. One month before the start of the carbon tax, the Treasury will mail every household a $100 check and an explanation of how the carbon tax reduces the typical household’s tax burden. • Apply the tax to the owners of coal mines at the mine gate, owners of petroleum refineries at the refinery gate, purchasers receiving imported refined petroleum product at ports of entry, and natural gas pipeline owners. • Set the tax rate at $25 per ton carbon dioxide for all fossil fuels effective one year after the legislation is signed into law. The rate will increase at the rate of inflation, as measured by the consumer price index for urban consumers, plus 5% per year. • Streamline and eliminate unnecessary regulations and subsidies. Once an economy-wide carbon tax is in place, businesses and consumers will have strong incentives to reduce the carbon intensity of their everyday activities. Eliminating Clean Air Act regulation of carbon dioxide emissions and related regulations can reduce the administrative burden and economic costs of the nation’s climate policy program without undermining climate goals. As a part of the tax reform, subsidies for energy through tax credits, accelerated depreciation, percentage depletion, expensing of intangible drilling costs, and other provisions would be phased out. • Enable businesses that capture carbon and store it underground or use fossil fuels as material inputs in manufacturing to earn tradable tax credits equal to the quantity of tons valued at the going carbon tax rate. • Evaluate the tax rate every five years. EPA will review the science, Treasury will review the economic costs of the carbon tax, and State Department will review the actions of other countries and progress in international negotiations. Based on these reviews, the President can recommend a change in the tax rate or its rate of growth to Congress. The recommendation will take the form of a joint resolution that can be voted up or down – or not voted on at all – but would not be subject to amendment. such as steel, aluminum, chemicals, cement, paper, and glass may be concerned about the competitiveness impacts of domestic regulations. If energy prices increase under Clean Air Act regulations (which the Environmental Protection Agency estimates will occur under the Clean Power Plan), but foreign competitors do not face comparable climate regulatory costs, then domestic firms may be at a competitive disadvantage in the U.S. market and abroad. For example, after the Paris Climate Conference, the legislative director for the United Steelworkers noted that “those [Chinese] imports carry with them a huge cost in the amount of carbon that was emitted on its way here.” The current regulatory approach cannot provide an explicit remedy to an increase in net imports P12 LONG-TERM CARBON POLICY: THE GREAT SWAP of carbon-intensive goods manufactured in unregulated or lightly regulated foreign markets. In contrast, a carbon tax could be designed to include a border tax – effectively imposing the carbon tax on imports from countries without a comparable domestic climate policy program. This would ensure a level playing field among U.S. energy-intensive manufacturers and their foreign competitors. global climate provides a strong case for taking action to reduce the prospect and magnitude of adverse climate change. Our country will come to regret foregoing this option if it does not undertake efforts today to avoid adverse, abrupt, and/or catastrophic climate change. This line of thinking is quite familiar to families and business leaders when they address other kinds of uncertain risks. Homeowners have insurance that compensates them in the event that a fire burns down their house. They pay a regular premium – giving up some income they could otherwise spend on consumption – in order to ensure that the value of their largest asset (for the vast majority of home-owners) is not at risk to a catastrophic event. A business may contract with other businesses in order to lock in prices for their output. The business may give up some expected profit, but in doing so it can avoid facing potential volatility about the prices for and hence returns to production. Families and businesses spend considerable resources to reduce the potential downside risks they face in a variety of contexts. Given the scale and nature of risks associated with climate change, a prudent course of action would be to undertake investments to reduce the likelihood of the worst outcomes. The balance of this memo describes in greater detail the case for an economy-wide carbon tax, the design of a carbon tax, and the potential use of carbon tax revenues. THE CASE FOR AN ECONOMYWIDE CARBON TAX The Certainty and Risks of a Changing Climate Families, businesses, and governments must confront two types of risks associated with climate change. First are the risks climate change poses for our health, safety, built infrastructure, agriculture, natural environments, economic activity, and more, around the world and for generations to come. The scientific literature on the potential climate change impacts – their magnitudes, their probabilities, and their timing – is characterized by uncertainty. While report after report from the National Academies of Sciences and the Intergovernmental Panel on Climate Change reviews and synthesizes the breadth of scholarly literature and acknowledges these uncertainties, they also make clear that human activities are changing and will continue to change the global climate and the net effect on human society is likely to be negative.1,2,3,4,5,6,7 Given uncertainty about the returns to mitigating the risks of climate change, it makes sense to pursue the lowest-cost ways of reducing greenhouse gas emissions. Ensuring that Americans realize the greatest gains on their investment will make more ambitious mitigation strategies more feasible, economically and politically. Conversely, a mix of low- and highcost policies – with dramatic differences across families, businesses, and regions of the country – may squander resources that could have supported greater mitigation if targeted more However one interprets these risks, it is important to recognize that uncertainty does not justify inaction. Instead, the uncertainty about potentially irreversible changes to the P13 LONG-TERM CARBON POLICY: THE GREAT SWAP effectively and result in investment that costs much more than the benefit it delivers. permissible emissions, creates emission allowances equal in sum to the aggregate cap that grants a regulated entity the right to emit a ton of emissions, and then allocates the allowances to the economy (e.g., through an auction, more often for free based on historic emissions). Under this program, firms can buy and sell allowances from each other and the secondary market for allowances that emerges reveals the carbon price. While there is certainty in the carbon price under a carbon tax, the capand-trade program yields an uncertain carbon price. In a number of prominent cases – such as the EU Emission Trading Scheme for carbon dioxide, the U.S. sulfur dioxide acid rain program, and the U.S. nitrogen oxides program – the volatility of emission allowances has been so great that it has exceeded the volatility of crude oil prices.8 CARBON PRICE CERTAINTY Firms that aim to maximize profits respond to prices. A business that faces higher prices for material inputs explores ways to economize on its use of materials. Higher wages may drive some businesses to invest in laborsaving equipment in order to reduce payroll’s contribution to costs. And higher costs of capital may induce some businesses to repair existing machinery instead of making new investments. In contrast, the vast majority of businesses in America do not face a price for carbon pollution. Businesses pay for labor, materials, and capital, and most businesses bear some cost for their water pollution, solid waste disposal, and most types of air pollution. These explicit and implicit prices create an incentive for firms to economize on their use of inputs and reduce their output of pollution by-products. While a carbon tax and cap-and-trade make the carbon price transparent, the vast array of regulatory and subsidy policies that reduce greenhouse gas emissions are characterized by implicit carbon prices. Even if policymakers say they oppose a carbon tax or cap-and-trade, their support for fuel economy standards, renewable subsidies, energy efficiency mandates and subsidies, fuel content regulations, and other policies increases the prices of either energy or the equipment and capital that use energy. The implicit carbon prices tend to be much higher for these policies than the prices set in past Congressional carbon tax proposals or estimated to arise under past Congressional cap-and-trade programs. These higher and quite variable implicit carbon prices mean the U.S. economy is paying much more to reduce a given amount of carbon pollution than it would under a carbon tax. Carbon pricing creates a cost for emitting carbon dioxide emissions just as there is a cost to businesses of hiring workers, buying materials, or complying with air quality standards. Setting a price on carbon motivates the business to seek out ways to reduce its carbon pollution so it can realize greater profits. Likewise, a carbon price creates incentives to individuals to change their behavior – i.e., reduce their carbon footprint – in order to pay less for carbon pollution. In practice, a carbon tax and a carbon dioxide cap-and-trade program can directly establish a price on carbon dioxide emissions. In a carbon tax, the government sets a tax per ton of emissions that must be paid on a regular (e.g., annual) basis by covered taxpayers (e.g., businesses). In a cap-and-trade program, the government sets an aggregate level of P14 LONG-TERM CARBON POLICY: THE GREAT SWAP FIGURE 1: Implicit Carbon Prices Under Various Energy and Climate Change Policies POLICY IMPLICIT CARBON PRICE NOTES $4.53/tCO2 June 2016 Auction CA Cap-and-Trade Program $12.80/tCO2 August 2016 Futures Price Wind RPS $45/tCO2 Academic article estimate CA Low Carbon Fuel Standard $119/tCO2 May 2016 Avg. Credit Price $222/tCO2 Academic article estimate $237/tCO2 Academic article estimate Regional Greenhouse Gas Initiative Corporate Average Fuel Economy Standards Cash for Clunkers a carbon price for internal project evaluation and investment analysis.12 For example, large American corporations, including manufacturers such as Colgate-Palmolive, General Motors, and Owens Corning; electric utilities such as AEP, Duke Energy, Exelon, and NRG Energy; oil companies such as ConocoPhillips and Exxon Mobil; and, information technology companies such as Google and Microsoft all employ carbon prices in internal planning ranging from $5/tCO2 to $85/tCO2. Formally integrating a carbon price in the assessment of business options reflects a sincere expectation that policies of one form or another will impose an explicit carbon price (e.g., a carbon tax) or an implicit carbon price (e.g., command-and-control regulations) on these companies’ business operations. Carbon Price Certainty and Business Planning Economists have long called for pricing carbon. In recent years, a much broader coalition of businesses has advanced the case for carbon pricing. In 2014, 74 countries and more than 1,000 businesses called on governments to price carbon through a carbon tax or emission trading systems.9 Likewise, more than 350 institutional investors – including BlackRock, CalPERS, and Standard Bank – representing more than $24 trillion in assets called for “stable, reliable, and economically meaningful carbon pricing.”10 In 2015, six international oil companies – BG Group, BP, Eni, Royal Dutch Shell, Statoil, and Total – called on governments to price carbon as part of “clear, stable, long-term, ambitious policy frameworks” to limit greenhouse gas emissions.11 The dramatic heterogeneity in expected carbon prices among these companies, however, also reflects the continued uncertainty about the form, timing, and ambition of climate This is more than simply the issuing of public statements. The Carbon Disclosure Project reported that more than 400 companies use P15 LONG-TERM CARBON POLICY: THE GREAT SWAP FIGURE 2: Carbon Pricing in Internal Corporate Planning 90 80 70 $/tCO2 60 50 40 30 20 10 in ob il g s n xo Ex Co s en Ow M rn ill Ph co no Co Xc el Y M En el er ip gy n lo le Go og BN ra Ge ne M ic lM ro ot so or ft s 0 Source: Carbon Disclosure Project Driving Emissions Reductions and Generating New Revenues Energy suppliers will increase the price of the fuels they sell in response to the carbon tax. This will effectively pass the tax down through the energy system, creating incentives for fuel-switching and investments in more energy-efficient technologies that reduce CO2 emissions.The real-world experience of firms and individuals responding to changing energy prices demonstrates the potential power of a carbon tax to drive changes in the investment and use of emission-intensive technologies. Higher gasoline prices in 2008 helped more change policy. As a result, some investments will likely move forward that would not have if the company knew with greater certainty or predictability what the effective carbon price would be in the future. Likewise, some investments may not move forward that would have had the company held a more accurate understanding of future carbon prices. This less-than-optimal investment risks lowering the returns to capital and inhibiting economic growth. P16 LONG-TERM CARBON POLICY: THE GREAT SWAP FIGURE 3: Estimated Carbon Tax Revenues and Carbon Emissions vs 2005 Emissions vs 2005 billions $ 60 -28% 40 -32% 20 -36% 0 -40% 20 20 20 20 20 20 20 30 -24% 29 80 20 28 -20% 20 27 100 20 26 -16% 20 25 120 20 24 -12% 23 140 22 -8% 21 160 20 20 -4% 20 19 180 18 0% 17 200 Notes: The red line represents carbon emissions (the right vertical axis) and the blue bars show carbon tax revenues (the left vertical axis.) Constructed by author based on Annual Energy Outlook 2014 side case analyses. fuel-efficient vehicles increase their market share, while reducing vehicle miles traveled by drivers of existing cars and trucks.13 In recent years, electric utilities responded to the dramatic decline in natural gas prices (and the associated increase in the relative coal-gas price ratio) by switching dispatch from coalfired power plants to gas-fired power plants, resulting in lower carbon dioxide emissions and the lowest share of U.S. power generation by coal in some four decades. Historically, higher energy prices have induced more innovation – measured by frequency and importance of patents – and increased the commercial availability of more energy-efficient products, especially among energy-intensive goods such as air conditioners and water heaters (Popp 2002). Imposing a carbon tax would provide certainty about the marginal cost of compliance, which reduces uncertainty about returns to investment decisions and eliminates the regulatory uncertainty that inhibits energy sector investment. Some carbon tax opponents claim that businesses will simply pay the tax and keep on polluting. This presumes that businesses would prefer to pay more tax than is necessary. This does not square with the long history of how P17 LONG-TERM CARBON POLICY: THE GREAT SWAP businesses operate under the tax code or how they respond to changes in energy prices. If a utility produces more power from its natural gas power plants than its coal plants when natural gas prices fall, then a utility is likely to do the same in response to relatively higher coal prices due to a carbon tax. information problem for the regulator is the fact that the opportunities for and costs of reducing pollution vary across businesses. Some have low-cost ways of reducing pollution while others have only high-cost pollution abatement approaches, but the regulator likely cannot identify and distinguish these types. As a result, a regulator who applies a common standard to all sources of pollution likely imposes greater costs than would be realized if the regulator could overcome the information problem and set standards that equate the marginal costs of regulatory compliance across all sources. To illustrate the potential impacts of a carbon tax on emissions, consider a $25 per ton carbon tax that increases 5 percent annually (this is based on the Energy Information Administration’s 2014 Annual Energy Outlook). This carbon tax would lower U.S. carbon dioxide emissions 26 percent by 2025 – consistent with our nation’s pledge at the Paris climate summit last year – and more While a regulator cannot know perfectly the pollution mitigation opportunities at all firms, it can create strong incentives to realize the costeffective outcome of equating marginal costs across all sources. A carbon tax delivers these strong incentives by leveraging businesses' profit motive. A business facing a carbon tax of, say, $25 per ton carbon dioxide will find it in its interest to seek out and exploit all emission abatement options that cost no more than $25/ tCO2. The business is better off paying a tax instead of investing in abatement that costs more than $25/tCO2. Firms will converge on the cost-effective outcome of equating their marginal costs of regulatory compliance with $25/tCO2, and thus among each other. As the carbon price increases over time, all businesses will have the incentive to invest in additional pollution abatement that costs less than the rising carbon tax. U.S. refineries and importers of petroleum products already pay a federal per barrel tax and coal mine operators already pay a federal per ton tax, so a national carbon tax could easily piggyback on these existing tax reporting systems. than 30 percent by 2030. In doing so, it would raise gross tax revenues by $130 billion to nearly $200 billion per year through 2030. Incentives for Investment Governments face a fundamental and insurmountable problem when considering policy options for reducing any type of pollution, and especially carbon pollution: businesses know and understand their opportunities for mitigating pollution better than the government. Any given regulator operates with incomplete information about these mitigation options in the business community. Complicating this Relying on the market-based approach of pricing carbon taps into the ingenuity of businesses and entrepreneurs. The technology-neutral approach allows any clever, emission-reducing idea to have consideration in the market. Instead of relying on a relatively small number of government staff to be creative in exploring P18 LONG-TERM CARBON POLICY: THE GREAT SWAP abatement options, letting the market investigate pollution control opportunities and, through the profit motive, attract many, many more individuals to tackle the problem can result in more emissions abatement at lower cost than any analyst would predict ex ante. and on some sources of emissions, while failing to affect the emissions of other categories of emissions altogether. Multiple regulations on some sources and no regulation on others has significant, adverse environmental impacts (the unregulated emissions will become larger shares of U.S. emissions) and economic costs (the difference between the effective carbon price on regulated emissions and the implicit zero price on unregulated emissions will continue to grow, reflecting declining bang for the buck). This is not only a problem for the regulator. Subsidizing climate-friendly technologies through the tax code, program rebates, and implicitly through technology-specific mandates (e.g., renewable portfolio standards) also encounters this information problem. These subsidies typically focus on a type of technology as opposed to its carbon emission characteristics. For example, a megawatthour of solar power receives credits that have been worth ten times as much as megawatthour of wind power in the Commonwealth of Massachusetts’ renewable portfolio standard. From the standpoint of the global climate and greenhouse gas emissions, it is not obvious why society benefits from paying ten times more for one kind of zero-carbon electricity than another kind of zero-carbon electricity. What’s more, the status quo provides much weaker incentives for innovation than an explicit carbon price. Given the need for innovation to deliver the next generation of low-carbon technologies in order to achieve long-term climate goals, governments should pursue policies that drive both deployment in existing climate-friendly technologies and research and development in new technologies. The failure of current policies to generate revenues – although they do create and transfer substantial economic value – further undermines innovation. Some of the revenue generated through a carbon tax could support investment in research and development. A much larger fraction of the revenues could be directed to businesses and individuals to address concerns about the distributional impacts of raising energy prices under climate policy. Under the status quo framework, energy and climate policies increase the price of energy and the price of energy-consuming durables (cars, appliances, etc.) without transferring resources to low-income households to adjust to these costs or they subsidize renewable and efficiency technologies that disproportionately benefit the well-off. Replacing Less Efficient Regulations and Subsidies What passes for climate change policy today is a patchwork of instruments – subsidies, regulatory mandates, and information programs – that were not initially designed with climate change in mind. These policies represent a short-term, stopgap measures to make some progress on climate, but cannot be relied upon to deliver on the ambitious long-term goals agreed to by world leaders at the 2015 Paris climate conference, the long-term goals agreed to by G7 heads of state, or the goals advanced by various environmental stakeholders. This complicated mix of policies is simultaneously overlapping and redundant in some industries For those concerned about competitiveness P19 LONG-TERM CARBON POLICY: THE GREAT SWAP pressures from foreign firms, the status quo does not provide any mechanism for mitigating these pressures. In fact, it increases the price of energy and the costs of energyconsuming equipment for U.S. manufacturers. The academic literature suggests that these competitiveness pressures are modest economic phenomena – other factors, such as trade policy, exchange rates, and automation have a more substantial impact than energy prices on competitiveness. Nonetheless, the political interest in policies to address adverse competitiveness impacts can only be met through new legislation. with a single, transparent, and predictable tax policy. The regulatory status quo imposes heavy administrative burdens and costs on businesses, deterring innovation and market entry. The opaque nature of incentives and mandates – as well as the appearance of political connections associated with technology-specific policies – have a chilling effect on entrepreneurs who could develop novel technologies, processes, practices, and other ideas that could mitigate climate change risks. Second, a carbon tax – with distributionally-fair tax reform – would be more progressive than the current approach to energy and climate Finally, conservatives also are critical of the energy policy status quo, if for different reasons than progressives and environmentalists. Without an alternative, however, they can’t do much to change it. Blocking new climate change measures, like a carbon tax, simply means that today’s inefficient jumble of sectoral policies– under the Clean Air Act, the Energy Policy Act, and other statutes – will continue. Because these policies aren’t as cost-effective as an economy-wide carbon tax, doing nothing essentially means higher energy costs with fewer environmental benefits. What’s more, today’s regulations are far more prescriptive and intrusive than a tax would be. A serious consideration of what the policy landscape will look like in the absence of new climate legislation suggests that all sides of this issue could secure a compromise that creates a win for all involved. The tradability of tax credits could be limited such that the tax credits could be traded only to firms with explicit carbon tax liabilities. policy. Subsidies to families for installing solar panels, purchasing hybrid and electric vehicles, and making home-related energy efficiency investments disproportionately benefit the wealthy. For example, recent research by University of California at Berkeley economists find that households in the top income quintile have received about 60 percent of clean energy federal income tax credits since 2006, while the bottom three quintiles have received only about 10 percent of these credits.14 A University of California at San Diego economist has shown that fuel economy standards – because of the long-term impacts on used car markets – are also regressive, imposing greater losses in personal welfare for low-income households than for high-income households.15 Of course, any policy that raises energy prices – cap-andtrade, renewable portfolio standards, biofuel Streamlining Multiple, Overlapping Policy Instruments Replacing today’s complicated jumble of overlapping policies with an economy-wide carbon tax would have many benefits. First, businesses would find it much simpler to comply P20 LONG-TERM CARBON POLICY: THE GREAT SWAP and low-carbon fuel mandates, etc. – are also likely to be regressive, unless they can generate revenues that are returned to the economy in a way to address the impacts on low-income households. pays the same amount per ton of emissions. Every zero-carbon technology would enjoy the same economic incentive in a market with a carbon tax. The carbon tax lets market competition pick the winners: businesses, ideas, thought-leaders, and technologies that can contribute to lower emissions. Such transparency builds confidence among citizens that their government is not playing favorites under pressure from special interests. Third, some of today’s energy and climate policies yield unintended, adverse impacts. For example, generous subsidies for electric vehicles in Georgia have encouraged people to buy more electric vehicles. That sounds like a good thing from a climate protection point of view. But those vehicles need power, and most of it in the Southeast United States is supplied by coal-burning plants. So the net effect of Georgia’s subsidies is to make its air cleaner in exchange for more regionally-dispersed air pollution and coal-based electricity-sector carbon dioxide emissions.16 In short, pushing aggressively for electric vehicles in regions with coal-intensive power systems – and no carbon or renewable policies – can make the environment worse. In addition, some subsidies simply transfer resources to households and businesses that were going to undertake the desired activity already. Under the Recovery Act, states implemented a “cash for appliances” program, quite similar to utility-sponsored rebate programs for EnergyStar-rated appliances. As many as 90 percent of all rebates claimed under these programs were by households that would have purchased an EnergyStar-rated appliance even in the absence of the rebate program.17 Indeed, economic modeling analyses show that a less-than-optimal mix of climate policies can perversely result in greater emissions and greater costs.18 Regulatory Preemption Designing a carbon tax to substitute for existing regulations and subsidies is politically fraught. It is unlikely that the businesses in the regulated community or many Republicans would support a carbon tax within a broader tax reform package without some form of regulatory relief. The environmental community may have reservations, however, about giving up regulatory authority over greenhouse gas emissions for the carbon tax. Consider three options for how to promote regulatory streamlining. First, there could be a straight trade of the carbon tax for Clean Air Act regulatory authority, other related regulatory authorities, related subsidies in the tax code, and possibly preemption of state policies. The simpler the climate policy landscape becomes, the more cost-effective and stronger the signals for innovation will be. The extent to which the reform can advance this regulatory and policy streamlining may depend on the pushback from vested interests. Second, the existing regulations could remain but the relevant statutory authorities would be revised such that these regulations could not be revised and made more stringent in the future. Thus, as the carbon price increases over time, Finally, a carbon tax is much more transparent to citizens than the existing welter of regulations and subsidies. A carbon tax creates a clear, level playing field. Every source of carbon pollution P21 LONG-TERM CARBON POLICY: THE GREAT SWAP the existing regulations would likely no longer serve as the binding constraint on covered businesses. Maintaining the existing suite of policies would address the environmental community concern that there could be backsliding of environmental performance under such a swap. taken into account.20 Other research shows how a carbon tax with well-designed refunds for families could be a progressive tax reform – leaving households at the bottom of the income distribution whole and only imposing costs on the top of the income distribution.21 It is likely that any politically successful tax reform will strike a balance between efficiency gains and a “fair” distribution, and a carbon tax can serve as a substantial revenue source to enable this balance. The reform should strive to make the tax code more competitive while also ensuring that the needs of those potentially most vulnerable under a carbon tax policy – low-income households as well as those living in communities reliant on coal production – are addressed through targeted tax relief and/or assistance. Third, there could be a formalized process of retrospective review of existing regulations accounting for the carbon tax. If an existing regulation passes a benefit-cost test under retrospective review, then it could remain. If not, then it would be eliminated. This could build on a bipartisan approach to retrospective review dating back to the Carter Administration and recent efforts by the Obama Administration to institutionalize retrospective review.19 Generating New Revenues for Tax Reform The U.S. government taxes both business profits and the labor income of workers. But it doesn’t tax the carbon pollution that is a byproduct of business operations. In short, society taxes the fruits of labor and the returns to capital— and hence discourages labor supply and investment — but not pollution. Labor and capital are overtaxed while carbon pollution is undertaxed. Smart tax reform would lower the taxes on the socially beneficial factors of production and raise taxes on the adverse byproducts of production. The American Recovery and Reinvestment Act of 2009 offers a cautionary lesson in failing to make tax relief palpable to citizens. The $100 billion to $200 billion in annual revenues from an economy-wide carbon tax could play an important role in making fiscal and tax reform add up. Carbon tax revenues would likely exceed, on an annual basis, the budget sequestration that called for blunt, politically unpopular cuts to U.S. domestic and defense spending. It is on par with the revenues that would be generated by eliminating the politically popular if economically inefficient home mortgage interest deduction in the U.S. tax code. It could finance a 2 percent payroll tax reduction (and then some), such as workers enjoyed in 2011 and 2012. These revenues could also help reduce significantly the deficit, which effectively A tax swap – for example, through a revenueneutral carbon tax and suite of income tax cuts – can address economic efficiency and distributional objectives. Some recent research shows that a carbon tax coupled with a welltargeted reform of the tax code could result in net economic growth relative to no tax swap – and this is even before the pro-growth benefits of streamlining the regulatory framework are P22 LONG-TERM CARBON POLICY: THE GREAT SWAP and leveraged additional actions by others. (And periods of U.S. inaction have had a chilling effect on the climate talks.) For example, the U.S. government received a strong positive response to the proposal and finalization of the Clean Power Plan. This strong reception, however, highlights the potential risks internationally if the courts throw out some or all of the Clean Power Plan. The cooperation on pledged goals has also translated into bilateral cooperation with China. In 2014, the U.S. and China announced jointly their pledges for the Paris Conference, which they followed up in 2015 with joint announcements on the Clean Power Plan and China’s plan to go nationwide with carbon dioxide cap-and-trade. translates into lower future taxes. The experience with a carbon tax in other jurisdictions holds positive lessons about the prospects of a tax swap rather than capand-trade programs. The province of British Columbia implemented a carbon tax in 2008 that is now C$30/tCO2 on all fossil fuels. The government coupled reductions in individual and corporate tax rates and provided a low-income household benefit that reflected a full recycling 22 of carbon tax revenues to the economy. Likewise, Sweden implemented a carbon tax in 1991 as a part of a tax reform package that lowered high income tax rates.23 In contrast, capand-trade programs that give away allowances for free do not generate revenues to finance income tax cuts. Moreover, the experience with state-level cap-and-trade programs in California and the northeast states suggests that most revenues finance energy efficiency and clean energy investments, not lower state income tax rates. An economy-wide carbon tax would clearly signal the seriousness with which the United States takes climate change. Moreover, it would establish a clear metric by which it could compare effort with other countries. Some scholars have emphasized that an explicit carbon price could serve as an important focal point for international coordination, and its transparency contrasts with the challenges of observing, measuring, and/or estimating emission mitigation efforts under quantitybased targets. Leveraging Greater International Cooperation U.S. efforts to reduce carbon pollution are a critical part of the global effort to combat climate change. In December 2015, the international community agreed to a new multilateral climate policy framework in Paris. The Paris agreement was unprecedented: nearly every country in the world pledged to reduce its greenhouse gas emissions and subject these pledges to policy surveillance under a transparency regime. In addition, the international community agreed to a “global stock-taking” every five years and a regular, periodic review and updating of national pledges. The updating of the domestic carbon tax described above could be scheduled to coincide with the results of the global stock-taking and timed to adjust in line with the updating of or submission of new pledges under the Paris framework. As the United States learns how other countries are faring in implementing their pledged goals, and as the international community assesses the need for more ambitious actions, the U.S. can adjust its carbon tax accordingly. Given the significant challenge of using the current patchwork approach to In recent years, U.S. action on climate change has had a positive impact on the negotiations P23 LONG-TERM CARBON POLICY: THE GREAT SWAP FIGURE 4: Carbon emissions per capita from direct energy and total energy consumption 25 Direct Energy CO2 All Energy CO2 CO2 per capita 20 15 10 5 0 1990 1995 2000 2005 2010 Source: Energy Information Administration State Energy Data System ramp up U.S. mitigation ambition much beyond the current U.S. pledge to lower emissions 26 to 28 percent below 2005 levels by 2025, a carbon tax would seriously enhance the credibility of the U.S. in future negotiations over its post2025 pledges. For that matter, given some disagreement among scholars whether the current suite of policies is sufficient for the U.S. to achieve its 2025 pledge, a carbon tax may be pivotal in ensuring attainment of this initial U.S. milepost under the Paris agreement. natural gas represented about 12 percent of the power market. Wind and solar power were about 1/10 of 1 percent of power generation. In 2015, coal’s share had declined 19 percentage points to 33 percent, with natural gas having a nearly identical market share (32.6 percent), and wind and solar power now providing more than 5 percent of U.S. electricity. Given that a coal-fired power plant emits about twice as much carbon dioxide as a natural gas plant to produce a kilowatt-hour of electricity, the shift from coal to natural gas and renewable sources of power has significantly reduced the U.S. electricity sector’s carbon intensity. Changing Energy System Sets Foundation for Carbon Pricing In the 25 years of debate over climate change policy – and implementation of policies with indirect impacts on greenhouse gas emissions – the U.S. energy system has evolved considerably. Around 1990, coal’s share of power generation exceeded 52 percent, while Beyond the composition of power, the demand for power has also changed. In the 1990s, power consumption grew more than 2 percent per year. Through the first half of the 2010s, however, P24 LONG-TERM CARBON POLICY: THE GREAT SWAP electricity consumption has not increased and 2015 power consumption was about 1 percent lower than 2010, despite real economic growth of 11 percent over this time. electricity prices would be slightly higher under a carbon tax than the 2006-2015 average. HOW TO DESIGN A CARBON TAX Design Principles A well-designed carbon tax would deliver on the environmental objectives of U.S. climate policy, promote cost-effective emissions abatement, and address distributional concerns through a transparent and administratively simple approach. In the transportation sector, biofuel’s share of personal transportation fuels has increased from about one-half of 1 percent in 1990 to about 10 percent today. The vast majority of the biofuels blended with motor gasoline are corn-based ethanol, and the climatic impacts of future biofuels penetration will depend on the fossil fuel intensity of their production. Demand for motor gasoline has fallen considerably from what had been expected a decade ago, reflecting higher fuel prices (even in light of the recent oil price decline), more stringent fuel economy standards, and changes in driving behavior. Environmental Integrity: The primary intent of a carbon tax is to mitigate the risks posed by climate change. Since carbon dioxide is the primary driver of climate change, a carbon tax is a very well-targeted policy instrument. By directly focusing the policy instrument on the problem, a carbon tax influences all margins of emissions-related activity – the use of fossil fuels, investment in equipment and capital that rely on energy, and innovation. The level of the carbon tax is critical in the extent to which the policy changes behavior on these margins and thus reduces emissions. The fall in energy consumption and the changing carbon intensity of energy consumption have resulted in a substantial decline in the carbon emission intensity of consumption. As Figure 4 shows, carbon dioxide emissions per capita,for all fossil fuel energy consumption have declined 17 percent over 2005-2014 to 17 tons per capita; also, emissions per capita for energy directly purchased by families and individuals – electricity, gasoline, and heating fuels (natural gas, heating oil, and LPG) – have declined 15 percent to about 7 tons per capita. As a result, a given carbon tax would have a smaller impact on household expenditures – at least 15 percent less impact – than it would have had ten years ago. Cost-effectiveness: A cost-effective carbon tax imposes the same price for emitting a unit of carbon dioxide emissions across all sources of emissions. Such an approach ensures the broadest possible base for the tax, which in turn allows for the largest possible revenue generation at least cost. This approach is equitable as well, because it treats all sources of pollution the same. It does not reward old, dirty facilities simply because they were built before 1970 (as is the case with a number of provisions of the Clean Air Act that have effectively exempted power plants from stringent regulations). And it does not create a complicated regulatory scheme that establishes one set of rules for “new sources” of carbon Moreover, energy prices are lower now than they have been for most of the past decade. Gasoline prices as well as residential natural gas and heating oil prices with a $25/tCO2 tax in 2017 would fall below the average prices over 20062015 for these fuels (see figure 5). Residential P25 LONG-TERM CARBON POLICY: THE GREAT SWAP FIGURE 5: Residential Energy Prices, 2006-2015 Average and 2017 with a $25 per ton Carbon Tax 16 14 12 10 8 6 4 2 0 Gasoline ($/gal) Natural Gas ($/MCF) Heating Oil ($/gal) Electricity (¢/kWh) 2006-2015 Average 2017 withEnergy $25/tCO2 Tax2014 side case analyses and Notes: Constructed by author using data from the Energy Information Administration’s Annual Outlook the June 2016 Short-Term Energy Outlook. emissions and a different set of rules for “existing sources.” A cost-effective tax makes it more likely that the climate policy maximizes net social benefits. Yet, in a democratic society, transparency is surely preferable to regulatory policies so complicated and obtuse that citizens cannot grasp their impact. A transparent price signal facilitates planning and investment by families and businesses relative to cap-and-trade, performance standards, and other policies with uncertain price impacts. A transparent cost also provides innovators and entrepreneurs with a clear target for the returns they need to make on their inventions. A carbon tax also communicates to our international partners that the United States is serious about cutting greenhouse gas emissions. Equity: Public and political support for a carbon tax will depend heavily on both its distributional impact and how its revenues are used. A “fair” carbon tax – recognizing that different constituencies and stakeholders may hold different opinions over what is “fair” – must address the distributional consequences across income groups, across geographic regions, and upon those most vulnerable to bearing adverse impacts of the tax and associated revenue use. Administrative Simplicity: A tax that is simple to understand, simple to monitor and administer, and simple to enforce is one that is more likely to Transparency: Some have argued that a carbon tax is politically vulnerable because it makes the costs of climate change policy transparent. P26 LONG-TERM CARBON POLICY: THE GREAT SWAP be complied with and drive intended behavioral responses, which, in the case of a carbon tax, is lower carbon dioxide emissions. paying the tax). For example, the business may purchase a more efficient boiler, install more efficient lighting, or switch to a lower-emitting fuel if it costs less than paying the tax (directly or indirectly through fuel and power purchases). If the tax rate is set equal to the benefit of reducing emissions, then these investments cost no more than the benefit they deliver to society. The last investment a business would profitably undertake to avoid paying a carbon tax is one in which the cost of the investment is effectively the same as the social benefit. This would signal that all the investments with positive social returns had been pursued. Setting the Carbon Tax A carbon tax would set the price per ton of carbon dioxide embodied in fossil fuels. A number of factors influence the setting of the tax level and how it changes over time. A carbon tax of $25 per ton is politically salient in light of current and recent state and national proposals. The State of Washington held a referendum on a $25 per ton tax that would finance a reduction in the state sales tax and rebates for lowerincome households.24In 2010, the bipartisan Domenici-Rivlin Debt Reduction Task Force seriously considered a $23 per ton carbon tax, and it received the greatest (but not unanimous) support among revenue alternatives the task force did not select.25 A number of carbon tax bills would set the tax rate in the vicinity of $25 per ton, including Sen. Sanders 2015 bill at $15 per ton in the first year (and surpassing $25 per ton within five years), Rep. Delaney’s 2015 bill starting at $30 per ton, and Rep. Inglis’s 2009 bill starting at $15 per ton in the first year (and surpassing $25 per ton within eight years).26, 27, 28 Published estimates of the benefits of reducing carbon dioxide emissions abound in the academic literature, and the U.S. government has issued its own estimates since 2010 to inform regulatory impact analyses for major rule-makings impacting carbon dioxide emissions.29,30,31 The so-called “social cost of carbon” approach used by the U.S. government is currently undergoing review by a National Research Council committee. The current, primary estimate is about $45 per ton and increases about 2% annually. While the current period of relatively low fuel prices would suggest this would be an opportune time to implement a carbon tax, there would still be concerns about the short-run impacts of imposing a carbon tax at this level. Thus, it would be important to consider a transition period over which a carbon tax would phase in. For example, the carbon tax could start at a much lower level, such as $25 per ton, and grow over time at a faster rate than the growth in the social cost of carbon. After converging with the social cost of carbon, the carbon tax could then track the rate of increase in the social cost of carbon. The tax rate that would maximize net social benefits is one in which the tax per ton of carbon dioxide is equal to the benefits of abating that ton of emissions. To illustrate this point, consider a business facing higher fuel prices as a result of a carbon tax. The appeal of the carbon tax is that does not dictate how a business reduces emissions; it simply creates an incentive for the firm to reduce emissions. This incentive is very strong for any business that aims to maximize its profits. The business will look for ways to reduce its emissions that cost less than paying the tax (or to pay for higher-priced fuel from the supplier that has the legal responsibility of An alternative approach would be to identify a P27 LONG-TERM CARBON POLICY: THE GREAT SWAP long-term emission target (e.g., 2050) for the country and then estimate a cost-effective price trajectory necessary to achieve that emission target. Such an approach has informed climate policy in the United Kingdom and France. This cost-effective carbon tax trajectory could be set at a relatively low level for its first year in order to address concerns about the transition. In either case, providing information about the long-term carbon tax – such as a tax schedule over time or a transparent escalator (e.g., X% + CPI-urban measure of inflation per year) – can inform and facilitate business and household planning and investment. permits an alternative, “upstream” approach. Instead of taxing carbon dioxide emissions, the carbon tax could be applied to the carbon content of fossil fuels. Due to the molecular properties of hydrocarbons, the complete combustion of a ton of coal, a cubic foot of natural gas, or a barrel of oil results in wellunderstood and precisely estimated quantities of carbon dioxide emissions. Applying the carbon tax to the carbon content of fossil fuels can then target the bottleneck in the product cycle of fossil fuels. Under such an upstream approach, refineries and importers of petroleum products would pay a tax based on the carbon content of their gasoline, diesel fuel, or heating oil. Coal-mine operators would pay a tax reflecting the carbon content of the tons extracted at the mine mouth. Natural-gas companies would pay a tax reflecting the carbon content of the gas they transport or import via pipelines or liquefied natural gas (LNG) terminals. This carbon content of fuels scheme would enable the policy to capture about 98 percent of U.S. CO2 emissions by covering only a few thousand sources as opposed to the hundreds of millions of smokestacks, tailpipes, etc. that emit CO2 under a system targeting actual emissions. Tax Base and Emissions Coverage Providing information about the long-term carbon tax – such as a tax schedule over time or a transparent escalator can inform and faciliate business, family planning, and investment U.S. air quality policy has typically covered emissions at the end of the pipe: regulations of sulfur dioxide emitted from coal-fired power plant smokestacks or standards for the emissions of nitrogen oxides from the tailpipes of cars. Implementing a carbon tax at the end of pipes – hundreds of millions of cars and trucks, tens of millions of homes that heat with natural gas or heating oil, and millions of commercial businesses, factories, and power plants – would be administratively daunting. The administrative costs of this so-called “downstream” approach – for families, for businesses, and for the government – could be so great as to undermine much of the economic benefits of implementing a cost-effective policy. A U.S. carbon tax would be administratively simple and straightforward to implement, since it could incorporate existing methods for fuel-supply monitoring and reporting to the government. The U.S. Energy Information Administration already tracks on a weekly, monthly, and annual basis the production, import, export, storage, and consumption of fossil fuel products. U.S. refineries and importers of petroleum products already pay a federal per barrel tax (to finance the Oil Spill Liability Trust Fund) and coal mine operators already pay a The nature of fossil fuel combustion, however, P28 LONG-TERM CARBON POLICY: THE GREAT SWAP federal per-ton tax (to finance the Black Lung Disability Trust Fund), so a national carbon tax could easily piggyback on these existing tax reporting systems. more amenable to other types of emission mitigation policies. Updating the Carbon Tax Ensuring a predictable carbon tax policy plays an important role in driving technological development and deployment. Firms will make better investment decisions, families and individuals will make plans that best suit their preferences, and innovators will focus efforts on carbon-oriented inventions when they can form expectations about how a climate policy will impact the quality, variation, and prices in goods and services. A predictable climate policy can increase the likelihood that their expectations are in line with what is realized in markets. Moreover, a predictable policy is more likely to endure politically, since it is typically the surprises that motivate calls for policy reform. The tax base would effectively be all fossil fuels. It could be extended to some nonfossil fuel sources of emissions. For example, carbon dioxide emissions associated with cement manufacturing could be covered with a smokestack monitoring approach (and expand the number of facilities responsible under law for reporting emissions and paying taxes by several hundred). There may be other, non-carbon greenhouse gas emissions the government could consider covering by the tax, but it is likely to become more administratively challenging going beyond fossil fuels. The question is whether the economic and environmental gains of a broader tax base justify the potentially greater administrative burden and complexity. Some non-carbon greenhouse gases may be This suggests two elements of carbon tax design to endure predictability. First, a carbon tax should be designed so the tax is known for many P29 LONG-TERM CARBON POLICY: THE GREAT SWAP years into the future. As in past Congressional bills, this could take the form of setting the tax in the first year and then establishing an annual percentage change to the tax that applies in perpetuity, or until changed by a future Congress. This differs from cap-and-trade and commandand-control regulations in which prices are not known with certainty, and historical experience shows dramatic cap-and-trade allowance price volatility.32 than five years in the future; (2) applying to only the level of the tax rate or the annual percentage change. The recommendation would take the form of a joint resolution of Congress that would not be subject to amendment (along the lines of Congressional Review Act resolutions on major rule-makings). Congress can vote the resolution up or down, or decide not to vote. In the case of a defeat of the resolution or a no vote, the status quo carbon tax rate scheme remains in place. The Presidential proposal could be synced with the timing of new rounds of mitigation pledging in the international negotiations, and thus the prospect of a Congressional vote could be used as leverage for more ambitious mitigation actions by other countries. Second, a durable carbon tax should nonetheless be adjusted in light of new information. As the science of climate change risks improves, as we learn more about the costs of reducing greenhouse gas emissions, and as the U.S. continues to cooperate with other countries in international climate policy, there may be reasons to adjust the carbon tax. For example, if scientific research suggests that adverse climate change impacts are likely to be more severe than previously believed, then a higher carbon tax could be justified. If the costs to the economy of reducing emissions are greater than initially anticipated, then a lower carbon tax could be justified. If the rest of the global community implements ambitious emission mitigation programs, then the U.S. could reciprocate by ramping up its carbon tax. To facilitate the predictability of these Presidential recommendations, the law authorizing the carbon tax will also require EPA, Treasury, and State to issue principles for carbon tax adjustments and “forward guidance.” These agencies would identify the data and analyses they consult in formulating their recommendation to the President, and, in periodic communications, note how they are interpreting the evolving evidence. Just as the Federal Reserve Federal Open Market Committee attempts to communicate its policy and the evidentiary basis for it so as to minimize surprises to the business and financial communities, this mechanism could allow for as-appropriate adjustments to occur that the private sector could expect as it tracks the same data as government officials. Here’s how such a gradual adjustment might work. Every five years, the EPA would publish a report on climate science and its implications for the carbon tax, the Treasury would publish a report on the economic and fiscal impacts of the carbon tax, and the State Department would publish a report on emission reduction efforts in other countries. Based on these reports, the President would submit a recommendation to Congress on how to adjust the carbon tax. This recommendation would be constrained by: (1) applying no earlier to the carbon tax schedule Capturing Carbon Some fossil fuels moving through the U.S. economy may not result in carbon dioxide emissions. For example, some hydrocarbons are used in the manufacturing of petrochemicals and the carbon is effectively embedded in the P30 LONG-TERM CARBON POLICY: THE GREAT SWAP product. A downstream source of emissions could invest in technology to capture and store carbon dioxide underground. For example, the Southern Company’s Kemper coal-fired power plant in Mississippi is expected to capture about two-thirds of its carbon dioxide emissions that it will then pump underground. In the former case, it would appear unfair to tax the embodied carbon in a barrel of oil that (as opposed to energy input) in manufacturing would be zero. The potential downside of a tax credit for these activities is that a firm would need to have sufficient tax liabilities in order to realize the economic benefit of the tax credit. Consider two options to address this risk. First, the tax credits could be tradable. Some tax law experts express concern about tradable tax credits because it adds complexity and the potential for fraud. The tradability of tax credits could be limited such that the tax credits could only be traded to firms with explicit carbon tax liabilities. While this may appear restrictive, it would likely be incorporated in contracts between manufacturers and their fuel suppliers who have the carbon tax obligation. Suppose, for example, that a fuel supplier sells natural gas for use as a feedstock to a chemical manufacturer. This company would pay the supplier a price equal to the competitive fuel price minus the carbon tax impact on that product and tradable tax credits for the product that would become embodied in the manufactured chemicals. A downstream source of emissions could invest in technology to capture and store carbon dioxide underground. goes into a manufactured product instead of the atmosphere. In the latter case, it would appear that an upstream carbon tax would not reward innovation in an emission-mitigation technology. To address these concerns, the carbon tax could be coupled with a crediting system. For example, a firm that captures and stores CO2 through geological sequestration, thereby preventing the gas from entering the atmosphere, could claim a tax credit equal in value on a per ton basis as the carbon tax. Likewise, manufacturers who could document the quantity of carbon embodied in their products (e.g., petrochemicals) would also be able to claim a tax credit equal in value to the carbon tax. This would result in the carbon capture and storage technology enjoying the same, transparent incentives as other emission-reduction technologies. The tax credit for manufacturers of embodied carbon products would effectively offset the higher input costs of fossil fuels such that the net tax on hydrocarbons used as a material input Alternatively, the government could provide grants equal in value to carbon tax credits to firms that don’t pay enough in taxes to take advantage of the credits. This approach was employed in the context of tax credits and grants to support renewable power investment in the 2009 American Recovery and Reinvestment Act.33 In contrast to the experience under the Recovery Act, in which the grants were a percentage of investment costs, the grants for carbon capture and storage and use as a material input in manufacturing would be equal in value to the carbon tax on a per ton basis. Border Tax Adjustment While stimulating the investment in low-carbon, P31 LONG-TERM CARBON POLICY: THE GREAT SWAP zero-carbon, and energy-efficient technologies, the implementation of a carbon tax could adversely affect the competitiveness of energyintensive industries. This competitiveness effect resulting from higher energy prices can result in firms relocating facilities to countries without meaningful climate change policies, thereby increasing emissions in these new locations and offsetting some of the environmental benefits of the policy. Such “emission leakage” may actually be relatively modest, because a majority of U.S. emissions occurs in non-traded sectors, such as electricity, transportation, and residential buildings. Energy-intensive manufacturing industries that produce goods competing in international markets may face incentives to relocate and will advocate for a variety of policies to mitigate these impacts. keep in mind that these emission leakage effects exist with any meaningful climate policy, whether through carbon tax, cap-and-trade, or status quo command-and-control authorities. Regardless of the economic magnitudes of these impacts from existing modeling and statistical analyses, it may be important politically to design the carbon tax to counter any potential competitiveness impacts, such as through a border tax adjustment. Indeed, it may make a carbon tax more politically palatable than the status quo mix of policies, since the existing policy framework cannot authorize a border tax. The political calculus for a border tax adjustment is likely to be influenced by the characteristics of the tax reform. A sufficiently generous reduction in, say, the corporate income tax rate financed by a carbon tax could make most manufacturers – even those with energy-intensive production processes – better off than under the status quo. Additional emission leakage may occur through international energy markets – as countries with climate policies reduce their consumption of fossil fuels and drive down fuel prices, those countries without emission mitigation policies increase their fuel consumption in response to the lower prices. Since leakage undermines the environmental effectiveness of any unilateral effort to mitigate emissions, international cooperation and coordination becomes all the more important. Political concerns about competitiveness may call for a carbon border tax that effectively imposes a tax on the carbon content on goods imported into the United States. If the U.S. implemented a carbon tax and threatened to impose a border tax on imports, then it could provide some negotiating leverage in multilateral fora to secure more stringent emission reduction policies among major trading partners, and thus minimize the competitiveness impacts. Also, it is important to HOW TO USE THE CARBON TAX REVENUES Returning Revenues to Families and Businesses Criticism of a carbon tax typically focuses on the tax component – the raising of revenue and its impacts on energy prices – without a careful consideration of how the use of the revenues could lower taxes on labor and capital income. No assessment of a carbon tax is complete – on distributional, economic efficiency, or political grounds – without analysis of the return of the revenues to the economy. The effects of a carbon tax on emission mitigation and the economy will depend in part on the amount and use of the revenues it generates. Using carbon tax revenues to finance tax reforms that improve the efficiency of the tax code could stimulate economic activity and offset some or all of the costs of cutting emissions. In addition, a relatively P32 LONG-TERM CARBON POLICY: THE GREAT SWAP cuts financed by a carbon tax will depend in large part on the nature of broader tax reform that would serve as the legislative vehicle for a carbon tax. The level and breadth of coverage of the carbon tax could be a function of revenue needs to ensure a revenue-neutral tax reform package as much as on climate change concerns. It is important to recognize that a more ambitious effort to cut personal and corporate income tax rates would likely require a more ambitious carbon tax in order to ensure revenue neutrality. small percentage of the annual carbon tax revenues could also support the research and development of climate-friendly technologies, which suffer underinvestment by the private sector. Raising energy prices could disproportionately impact low-income households, since a larger fraction of their budgets is dedicated to energy expenditures. The regressive nature of a carbon tax can be mitigated through the recycling of revenues back to the economy. For example, British Columbia’s economywide carbon tax program returns all revenues to the economy by cutting corporate and individual income tax rates and through a means-tested Low Income Climate Action Tax Credit. If a carbon tax is part of a broader fiscal and tax reform, the overall progressivity Given this premise, let me recommend one way carbon revenues could be recycled. First, the carbon tax revenues could enable a reduction in the payroll tax rate all workers pay. A 20 percent reduction in the employee’s contribution payroll taxes would use approximately $100 billion of the carbon tax revenues annually, based on current payroll tax levels. Given the expected growth in carbon tax revenues over time, this 20 percent reduction in the payroll tax could be financed without any net reduction in receipts to Social Security over time. Second, a small fraction of the carbon tax could finance a coal communities transition program. For example, simply allocating 2 percent of the carbon tax revenues to this program would deliver about $30 billion in support over a ten-year window. Third, another small fraction of the revenues could be dedicated for research and development in innovative energy technologies. This would ensure that there are more low-cost ways of reducing emissions available over time, which would create greater environmental benefits and reduce the economic cost of the carbon tax. Finally, the balance of the revenues could be used to lower corporate tax rates. This could Using carbon tax revenues to finance tax reforms that improve the efficiency of the tax code could stimulate economic activity and offset some or all of the costs of cutting emissions. of the package will depend in part on the use of carbon tax revenues, but more substantially on any potential decisions regarding entitlement spending (especially meanstested Medicaid) and changes to the tax code for businesses and individuals. While it is important to take into account the distributional impacts of a carbon tax – and not only by income group, but also geographically and potentially for energyintensive industries (see more on this below on competitiveness) – the exact mix of tax P33 LONG-TERM CARBON POLICY: THE GREAT SWAP be quite substantial, especially if the carbon tax is accompanied by an elimination of energy tax expenditures. carbon tax to offset a cut in the payroll tax rate. This could be noted both in workers’ paystubs and in a carbon tax dividend check they receive. The American Recovery and Reinvestment Act of 2009 offers a cautionary lesson in failing to make tax relief palpable to citizens. Thanks to this major stimulus bill, 95 percent of working Americans received a tax cut – in the form of changes in withholding rates on regular paychecks – but less than 10 percent indicated that they knew of the tax reductions when surveyed in a 2010 New York Times/CBS News poll.35 Making the Tax Benefits Visible Some of the public may be skeptical that a carbon tax could effectively finance lower taxes. This is not an unfounded belief, since statelevel cap-and-trade programs in California and the northeast have used revenues from auction emission allowances to finance energy spending programs, not cuts in tax rates. Indeed, some environmental groups in Washington opposed the state carbon tax referendum because the revenues would be used to cut the sales tax rate and provide low-income rebates, instead of financing clean energy programs.34 Moreover, to the extent that a carbon tax increases the price level, it would result in an adjustment in social security benefits through cost-of-living adjustments. In announcing annual inflation adjustments, the government could explain how carbon tax revenues enable an increase. In this way, the government would offset the higher energy costs that would otherwise fall on elderly Americans living on fixed incomes. To make the recycling of revenues back to the economy through lower tax rates salient and credible, the government should launch the carbon tax program by mailing every household a check for $100 a month before the carbon tax starts. British Columbia’s successful carbon tax CONCLUSION British Columbia’s successful carbon tax began this way, and it is similar to how the 2001 Bush tax cuts were implemented with checks mailed to households. The failure to mobilize sufficient effort to combat climate change reflects the difficult political economy that characterizes the problem.36 The task of reducing emissions yields a global public good that no individual, firm, or country has a strong incentive to produce unilaterally; imposes near-term costs on businesses and families with benefits spread out over decades and centuries; risks raising costs for domestic businesses that compete with untaxed foreign competitors; delivers uncertain returns, given uncertainties in climate science, multilateral coordination, market behavior, and technological innovation; and requires a fundamental transformation of the energy foundation of modern industrial began this way, and it is similar to how the 2001 Bush tax cuts were implemented with checks mailed to households. The checks would be accompanied with information explaining how a family may face lower taxes (depending on the nature of the tax reform) as the carbon tax is implemented. Suppose, for example, that policymakers use a P34 LONG-TERM CARBON POLICY: THE GREAT SWAP economies. Moreover, the distribution of a climate change policy’s benefits and costs varies across space and time, as well as among various political constituencies and special interests. To grossly simplify the problem, the challenge is that future, unborn generations will enjoy the benefits of climate policy while the current generation, and in particular those reaping substantial returns from a status quo that fails to address climate change, will bear the costs. Given this description of the problem, it’s not too surprising that the United States does not have a coherent, comprehensive climate change policy. How does a carbon tax address these challenges? It doesn’t, but it’s important to recognize that there are policy scenarios in which it doesn’t have to. While this paper has focused on the motivation, design, and benefits of a carbon tax, the likely path forward for a carbon tax in the United States is likely as a part of a larger tax and fiscal reform package. Crafting a carbon tax that (a) delivers revenues to enable cutting of tax rates on families and businesses; and (b) substitutes a transparent, administratively simple, durable, and costeffective climate policy for the complicated status quo framework can shift the economics and politics of this issue in a way that could break the decade-plus gridlock on national climate policy. P35 LONG-TERM CARBON POLICY: THE GREAT SWAP Endnotes 1. Committee on the Science of Climate Change. 2001. Climate Change Science: An Analysis of Some Key Questions. National Research Council. National Academy Press, Washington, DC. http://www.nap.edu/read/10139/chapter/1 2. Committee on America’s Climate Choices. 2011. America’s Climate Choices. National Research Council. National Academy Press, Washington, DC. http://www.nap.edu/catalog/12781/americas-climate-choices 3. Intergovernmental Panel on Climate Change. 1990. Climate Change: The IPCC Scientific Assessment. Cambridge University Press, Cambridge, England. https://www.ipcc.ch/publications_and_data/publications_ipcc_first_assessment_1990_wg1.shtml 4. Intergovernmental Panel on Climate Change. 1996. Climate Change 1995: The Science of Climate Change. Cambridge University Press, Cambridge, England. https://www.ipcc.ch/ipccreports/sar/wg_I/ipcc_sar_wg_I_full_report.pdf 5. Intergovernmental Panel on Climate Change. 2001. Climate Change 2001: The Scientific Basis. Cambridge University Press, Cambridge, England. https://www.ipcc.ch/ipccreports/tar/wg1/index.htm 6. Intergovernmental Panel on Climate Change. 2007. Climate Change 2007: The Physical Science Basis. Cambridge University Press, Cambridge, England. http://www.ipcc.ch/publications_and_data/publications_ipcc_fourth_assessment_report_wg1_report_the_physical_ science_basis.htm 7. Intergovernmental Panel on Climate Change. 2013. Climate Change 2013: The Physical Science Basis. Cambridge University Press, Cambridge, England. https://www.ipcc.ch/report/ar5/wg1/ 8. Aldy, Joseph E. and W. Kip Viscusi. 2014. Environmental Risk and Uncertainty. In: Handbook of the Economics of Risk and Uncertainty, Volume 1, Mark J. Machina and W. Kip Viscusi, eds., Elsevier, 601-649. 9. World Bank. 2014. Pricing Carbon. http://www.worldbank.org/en/programs/pricing-carbon 10. Global Investor Statement on Climate Change, January 2015. http://www.iigcc.org/files/press-release-files/GISCC13Jan2015.pdf 11. Letter to Christiana Figueres, Executive Secretary of the UNFCCC and Laurent Fabius, President of COP-21 from the Chief Executives of BG Group plc, BP plc, Eni S.pA., Royal Dutch Shell plc, Statoil ASA, and Total S.A. http://www.bp.com/content/dam/bp/pdf/press/payingfor-carbon.pdf 12 CDP. 2015. Putting a Price on Risk: Carbon Pricing in the Corporate World. https://www.cdp.net/CDPResults/carbon-pricing-in-the   corporate-world.pdf 13. Ramey, Valerie. 2011. Oil, Automobiles, and the U.S. Economy: How Much Have Things Really Changed? In: NBER Macroeconomics Annual 2010, volume 25. Chicago: University of Chicago Press, 333-367. 14. Borenstein, Severin, and Lucas W. Davis. 2015 The Distributional Effects of US Clean Energy Tax Credits. In: Tax Policy and the Economy, Volume 30. University of Chicago Press. 15. Jacobsen, Mark. 2013. Evaluating U.S. Fuel Economy Standards in a Model with Producer and Household Heterogeneity. American Economic Journal: Economic Policy 5(2). 16. Holland, Stephen P., Erin T. Mansur, Nicholas Z. Muller, and Andrew J. Yates. 2015. Environmental Benefits from Driving Electric Vehicles? NBER Working Paper 21291. Cambridge, MA: National Bureau of Economic Research. 17. Houde, Sébastien and Joseph E. Aldy. 2014. Belt and Suspenders and More: The Incremental Impact of Energy Efficiency Subsidies in the Presence of Existing Policy Instruments. NBER Working Paper 20541. 18. Kalkuhl, Matthias, Ottmar Edenhofer, and Kai Lessman. 2013. Renewable Energy Subsidies: Second-Best Policy or Fatal Aberration for Mitigation? Resource and Energy Economics 35(3): 217-234. 19. Aldy, Joseph E. 2014. Learning from Experience: An Assessment of the Retrospective Reviews of Agency Rules and Evidence for Improving the Design and Implementation of Regulatory Policy. Commissioned by the Administrative Conference of the United States, October 17. https://www.acus.gov/sites/default/files/documents/Aldy%2520Retro%2520Review%2520Draft%252011-17-2014.pdf 20. Parry, Ian WH, and Antonio M. Bento. 2000. Tax Deductions, Environmental Policy, and the “Double Dividend” Hypothesis. Journal of Environmental Economics and Management 39(1): 67-96. 21. Metcalf, Gilbert E. 2007. A Proposal for a U.S. Carbon Tax Swap. The Hamilton Project Working Paper. The Brookings Institution, Washington DC. P36 LONG-TERM CARBON POLICY: THE GREAT SWAP 22. Aldy, Joseph E. and Robert N. Stavins. 2012. The Promise and Problems of Pricing Carbon: Theory and Experience. Journal of Environment and Development 21(2): 152-180. 23. Speck, Stefan. 2008. The Design of Carbon and Broad-Based Energy Taxes in European Countries. Vermont Journal of Environmental Law 10: 31-59. 24. Purzycki, Michael. 2016. A Model Carbon Tax. Washington Monthly, August 5, 2016. http://washingtonmonthly.com/2016/08/05/amodel-carbon-tax/ 25. The Debt Reduction Task Force. 2010. Restoring America’s Future. Bipartisan Policy Center. November, 2010. http://cdn.bipartisanpolicy. org/wp-content/uploads/sites/default/files/BPC%20FINAL%20REPORT%20FOR%20PRINTER%2002%2028%2011.pdf 26. Climate Protection and Justice Act of 2015. S. 2399, 114th Congress, 1st Session. https://www.congress.gov/114/bills/s2399/BILLS114s2399is.pdf 27. Tax Pollution, Not Profits Act, H.R. 2202, 114th Congress, 1st Session. https://www.congress.gov/114/bills/hr2202/BILLS-114hr2202ih. pdf 28. Raise Wages, Cut Carbon Act of 2009. H.R. 2380, 111th Congress, 1st Session. https://www.gpo.gov/fdsys/pkg/BILLS-111hr2380ih/ pdf/BILLS-111hr2380ih.pdf 29. Interagency Working Group on Social Cost of Carbon. 2010. Technical Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866. February 2010. https://www3.epa.gov/otaq/climate/regulations/scc-tsd.pdf 30. Interagency Working Group on Social Cost of Carbon. 2013. Technical Support Document: Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866. May 2013. https://www.whitehouse.gov/sites/default/files/omb/ inforeg/social_cost_of_carbon_for_ria_2013_update.pdf 31. Interagency Working Group on Social Cost of Carbon. 2015. Technical Support Document: Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis Under Executive Order 12866. July 2015. https://www.whitehouse.gov/sites/default/files/omb/ inforeg/scc-tsd-final-july-2015.pdf 32. Aldy, Joseph E. and W. Kip Viscusi. 2014. Environmental Risk and Uncertainty. In: Handbook of the Economics of Risk and Uncertainty, Volume 1, Mark J. Machina and W. Kip Viscusi, eds., Elsevier, 601-649. 33. Aldy, Joseph E. 2013. A Preliminary Assessment of the American Recovery and Reinvestment Act’s Clean Energy Package. Review of Environmental Economics and Policy 7(1): 136-155. 34. Mankiw, N. Gregory. 2015. The Key Role of Conservatives in Taxing Carbon. New York Times, Economic View, September 4, 2015. http:// www.nytimes.com/2015/09/06/upshot/the-key-role-of-conservatives-in-taxing-carbon.html 35. Cooper, Michael. 2010. From Obama, the Tax Cut Nobody Heard of. New York Times, October 18, 2010. http://www.nytimes. com/2010/10/19/us/politics/19taxes.html 36. Aldy, Joseph E. 2016. Mobilizing Political Action on Behalf of Future Generations. The Future of Children 26(1): 157-178. P37 P38 LONG-TERM CARBON POLICY: THE GREAT SWAP The Progressive Policy Institute is a catalyst for policy innovation and political reform based in Washington, D.C. Its mission is to create radically pragmatic ideas for moving America beyond ideological and partisan deadlock. Founded in 1989, PPI started as the intellectual home of the New Democrats and earned a reputation as President Bill Clinton’s “idea mill.” Many of its mold-breaking ideas have been translated into public policy and law and have influenced international efforts to modernize progressive politics. © 2016 Progressive Policy Institute All rights reserved. Progressive Policy Institute 1200 New Hampshire Ave NW, Suite 575 Washington, DC 20036 Tel 202.525.3926 Fax 202.525.3941 info@ppionline.org progressivepolicy.org P40 From: To: Cc: Subject: Date: Mahoney, Jo-Ann Bob Stump Gill, Susan RE: Invitation to Harvard Electricity Policy Group Scottsdale Session Wednesday, November 30, 2016 2:39:52 PM Bob, We are delighted that you can attend!  We will be going to dinner at Sassi, on Doug Little’s recommendation to Ashley.   Of course, you are welcome to bring a guest.  I look forward to seeing you!  Best, Jo-Ann   From: Bob Stump [mailto:bstump@azcc.gov] Sent: Wednesday, November 30, 2016 4:30 PM To: Mahoney, Jo-Ann Subject: Re: Invitation to Harvard Electricity Policy Group Scottsdale Session   Jo-Ann, this is a great agenda - thanks, and I'm looking forward to it! My last HEPG (as an elected, at least!).  Please let me know if I can be of help.  Bob Sent from my iPhone On Nov 29, 2016, at 12:06 PM, Mahoney, Jo-Ann wrote: Dear Bob,   I hope this finds you well.  As you know, our next session will be held in Scottsdale on Thursday-Friday, December 8-9, 2016 at the Four Seasons Troon North.  I apologize for the late notice, but it took Bill a very long time to put this meeting together.  Our Thursday panels will focus on:  energy storage policy and the dissonance between competitive markets and resource preference mechanisms.  On Friday morning we will turn our attention to climate policy given the recent elections. (Agenda attached.)   You are welcome to attend as much of the meeting as your schedule allows.   We would also invite you to join us at our conference reception and dinner on Thursday evening.    We hope that you will be with us at the next HEPG session.  Kindly return the registration form to Susan Gill in our office.   Best, Jo-Ann Mahoney   Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu     Policy Dissonance: Pursuing Contradictory,  Perhaps Irreconcilable, Paths of Competitive Markets and Choosing Resource Preferences   In looking at the evolution of electricity markets over the past few years, it is possible to conclude that we are, perhaps unintentionally, pursuing two contradictory -perhaps even irreconcilable -- goals. On the one hand, we have, over the past two or three decades been committed to a fully competitive generating market, and in many states, competitive retail supply model. At the same time, through subsidies, crosssubsidies, and set aside markets, we have been putting in place (or attempting to do so) mechanisms to identify resource preference in ways that appear designed to alter results that the market may otherwise produce.  These mechanisms include, among other measures, renewable portfolio standards, favorable pricing for non-dispatchable resources such as rooftop solar (e.g. retail net metering and “value” pricing), special treatments for non-emitting generators such as ZECs for nuclear plants, state mandated (or approved) “reliability” decisions affording special treatment to favored plants and efforts, and various efforts to manipulate capacity markets. Indeed, developing a robust, competitive, emissions trading market has also been handicapped by similar efforts to explicitly identifying preferred resources. How seriously are these trends undermining competition in the market place? Are we, perhaps inadvertently, turning away from markets and back toward the old regulatory model? Or, are these divergent trends reconcilable in some fashion, and how?   Treatment of Storage Resources Storage is an increasing focus in electricity markets, but it is still highly uncertain as to how it should be viewed and treated by regulators. Should storage be allowed to participate as generation, transmission or another asset type? Can storage serve multiple purposes in one market? How can asset owners secure cost recovery in regulated and competitive markets? Is it  inherent that traditional transmission and/utilities must own the asset? How might owners/operators of intermittent resources use storage to reduce intermittency and how does that affect its treatment on a regulatory level? To what extent should storage be treated as energy or capacity, or as an ancillary service provider? Is it necessary or even useful to subsidize storage in order to accelerate its evolution into commercially viability?  Should storage at the distribution level be treated similarly to storage at on the high voltage system? Should the pricing of distributed intermittent resources be done in such a way as to incentivize the installation of storage? A Window of Opportunity: Changing Climate Policy Given the sudden shift in the political tectonic plates, there may be a window of opportunity to refashion major aspects of the electricity system.  The confluence of a possible major Federal tax reform, expanded spending on infrastructure investment, and redirection of national climate policy creates a new environment.  Tax reform and national infrastructure spending could make the revenue raising aspects of a carbon tax part of the solution.  And a carbon tax could be a central part of a major change in approach to accounting for the costs of energy externalities, allowing efficient approaches that replace other more intrusive and expensive approaches to environmental protection.  Part of this discussion will accentuate the debate on the social cost of carbon in this context.  The subject is both controversial and important.  How do we define and estimate the social cost of carbon?  What do we know about the key inputs and uncertainties?  How do we translate policy analysis into a workable system for a carbon tax?  How would a national carbon tax interact with state policies for cleaner energy?  What current or planned cleaner energy policies would or should change if there is a carbon tax?  What role will a carbon tax play in our energy future?     From: To: Subject: Date: Beth L. Soliere Bob Stump RE: Invitation to Harvard Electricity Policy Group Scottsdale Session Tuesday, November 29, 2016 2:44:18 PM Yes to everything?   From: Bob Stump Sent: Tuesday, November 29, 2016 2:44 PM To: Beth L. Soliere Subject: Fwd: Invitation to Harvard Electricity Policy Group Scottsdale Session   Sent from my iPhone Begin forwarded message: From: "Mahoney, Jo-Ann" Date: November 29, 2016 at 12:06:25 PM MST To: "bstump@azcc.gov" Subject: FW: Invitation to Harvard Electricity Policy Group Scottsdale Session Dear Bob,   I hope this finds you well.  As you know, our next session will be held in Scottsdale on Thursday-Friday, December 8-9, 2016 at the Four Seasons Troon North.  I apologize for the late notice, but it took Bill a very long time to put this meeting together.  Our Thursday panels will focus on:  energy storage policy and the dissonance between competitive markets and resource preference mechanisms.  On Friday morning we will turn our attention to climate policy given the recent elections. (Agenda attached.)   You are welcome to attend as much of the meeting as your schedule allows.   We would also invite you to join us at our conference reception and dinner on Thursday evening.    We hope that you will be with us at the next HEPG session.  Kindly return the registration form to Susan Gill in our office.   Best, Jo-Ann Mahoney   Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu     Policy Dissonance: Pursuing Contradictory,  Perhaps Irreconcilable, Paths of Competitive Markets and Choosing Resource Preferences   In looking at the evolution of electricity markets over the past few years, it is possible to conclude that we are, perhaps unintentionally, pursuing two contradictory -perhaps even irreconcilable -- goals. On the one hand, we have, over the past two or three decades been committed to a fully competitive generating market, and in many states, competitive retail supply model. At the same time, through subsidies, crosssubsidies, and set aside markets, we have been putting in place (or attempting to do so) mechanisms to identify resource preference in ways that appear designed to alter results that the market may otherwise produce.  These mechanisms include, among other measures, renewable portfolio standards, favorable pricing for non-dispatchable resources such as rooftop solar (e.g. retail net metering and “value” pricing), special treatments for non-emitting generators such as ZECs for nuclear plants, state mandated (or approved) “reliability” decisions affording special treatment to favored plants and efforts, and various efforts to manipulate capacity markets. Indeed, developing a robust, competitive, emissions trading market has also been handicapped by similar efforts to explicitly identifying preferred resources. How seriously are these trends undermining competition in the market place? Are we, perhaps inadvertently, turning away from markets and back toward the old regulatory model? Or, are these divergent trends reconcilable in some fashion, and how?   Treatment of Storage Resources Storage is an increasing focus in electricity markets, but it is still highly uncertain as to how it should be viewed and treated by regulators. Should storage be allowed to participate as generation, transmission or another asset type? Can storage serve multiple purposes in one market? How can asset owners secure cost recovery in regulated and competitive markets? Is it  inherent that traditional transmission and/utilities must own the asset? How might owners/operators of intermittent resources use storage to reduce intermittency and how does that affect its treatment on a regulatory level? To what extent should storage be treated as energy or capacity, or as an ancillary service provider? Is it necessary or even useful to subsidize storage in order to accelerate its evolution into commercially viability?  Should storage at the distribution level be treated similarly to storage at on the high voltage system? Should the pricing of distributed intermittent resources be done in such a way as to incentivize the installation of storage? A Window of Opportunity: Changing Climate Policy Given the sudden shift in the political tectonic plates, there may be a window of opportunity to refashion major aspects of the electricity system.  The confluence of a possible major Federal tax reform, expanded spending on infrastructure investment, and redirection of national climate policy creates a new environment.  Tax reform and national infrastructure spending could make the revenue raising aspects of a carbon tax part of the solution.  And a carbon tax could be a central part of a major change in approach to accounting for the costs of energy externalities, allowing efficient approaches that replace other more intrusive and expensive approaches to environmental protection.  Part of this discussion will accentuate the debate on the social cost of carbon in this context.  The subject is both controversial and important.  How do we define and estimate the social cost of carbon?  What do we know about the key inputs and uncertainties?  How do we translate policy analysis into a workable system for a carbon tax?  How would a national carbon tax interact with state policies for cleaner energy?  What current or planned cleaner energy policies would or should change if there is a carbon tax?  What role will a carbon tax play in our energy future?     From: To: Subject: Date: Attachments: Beth L. Soliere Bob Stump Fwd: Reimbursement for Washington HEPG Thursday, November 03, 2016 1:33:29 PM HCOM_non-employee_reimbursement_form.pdf ATT00001.htm missing_receipt.pdf ATT00002.htm w-9-blank.pdf ATT00003.htm She must be new. I sent the reimbursement form to JoAnn.  Begin forwarded message: From: "Gill, Susan" To: "Bob Stump" Cc: "Beth L. Soliere" Subject: Reimbursement for Washington HEPG Bob, We were glad that you could join us for the Harvard Electricity Policy Group’s EightFourth Plenary Session in Washington DC last month. In order to process your travel reimbursements, would you please fill out and sign the attached forms? Please mail the original receipts to: Susan Gill M-RCBG Harvard Kennedy School 79 JFK St., Belfer 501 Cambridge, MA 02138   If you have not previously received a reimbursement from HEPG or if your contact information has changed, please be sure to send us W-9, which is required by the IRS. Please let me know if you have any questions. Regards, Susan     Susan Gill Program Coordinator Mossavar-Rahmani Center for Business & Government Harvard Kennedy School Weil Hall 79 JFK St, Cambridge MA 02138 Tel: 617.495-9379 Website Twitter Facebook Listserv   HARVARD UNIVERSITY MISSING RECEIPT AFFIDAVIT Missing Receipt Affidavits lacking the required information or documentation will be returned to the authorized signer. Airline Tickets Attached is a copy of the itinerary invoice and proof of payment (i.e., credit card statement, cancelled check) Hotel Folio Attached is a copy of the hotel folio and proof of payment (i.e., credit card statement) -ORI certify that I have contacted the hotel and was unable to obtain a copy of the hotel folio. Please reimburse me based on the following information and proof of payment: Date # of nights Hotel/City Daily Rate Total Car Rental Agreement Attached is a copy of the car rental agreement and proof of payment (i.e., credit card statement) -ORI certify that I have contacted the rental car agency and was unable to obtain a copy of the car rental agreement Please reimburse me based on the following information and proof of payment: Dates Rental Company Car Class* # of Days Total *C=Compact, M=Mid-size, F= Full-size Date B, L, D* Meals (list each meal separately) Restaurant/City # of People** Total *B=Breakfast, L=Lunch, D=Dinner (**Name of attendees and business purpose is required on Expense Report or Pcard Settlement System) Miscellaneous For PCard transactions include a copy of the sweep report from the Pcard Settlement System or a copy of the credit card statement. Date Description (in detail) Total I, the undersigned, certify (a) that each expense described above, reported on Web Reimbursement Report ,or on the Pcard Settlement System Report was/were lost or not obtained, and (b) that number these expenses have not yet nor will again be submitted to Harvard University or any other organization for reimbursement or tax purposes. Signature of Payee/Card holder Authorized Signature REQUIRED REQUIRED Date Date ___ W-9 Form (Rev. December 2011) Department of the Treasury Internal Revenue Service Request for Taxpayer Identification Number and Certification Give Form to the requester. Do not send to the IRS. Print or type See Specific Instructions on page 2. Name (as shown on your income tax return) Business name/disregarded entity name, if different from above Check appropriate box for federal tax classification: Individual/sole proprietor C Corporation S Corporation Partnership Trust/estate Exempt payee Limited liability company. Enter the tax classification (C=C corporation, S=S corporation, P=partnership) ▶ Other (see instructions) ▶ Address (number, street, and apt. or suite no.) Requester’s name and address (optional) City, state, and ZIP code List account number(s) here (optional) Part I Taxpayer Identification Number (TIN) Enter your TIN in the appropriate box. The TIN provided must match the name given on the “Name” line to avoid backup withholding. For individuals, this is your social security number (SSN). However, for a resident alien, sole proprietor, or disregarded entity, see the Part I instructions on page 3. For other entities, it is your employer identification number (EIN). If you do not have a number, see How to get a TIN on page 3. Social security number Note. If the account is in more than one name, see the chart on page 4 for guidelines on whose number to enter. Employer identification number Part II – – – Certification Under penalties of perjury, I certify that: 1. The number shown on this form is my correct taxpayer identification number (or I am waiting for a number to be issued to me), and 2. I am not subject to backup withholding because: (a) I am exempt from backup withholding, or (b) I have not been notified by the Internal Revenue Service (IRS) that I am subject to backup withholding as a result of a failure to report all interest or dividends, or (c) the IRS has notified me that I am no longer subject to backup withholding, and 3. I am a U.S. citizen or other U.S. person (defined below). Certification instructions. You must cross out item 2 above if you have been notified by the IRS that you are currently subject to backup withholding because you have failed to report all interest and dividends on your tax return. For real estate transactions, item 2 does not apply. For mortgage interest paid, acquisition or abandonment of secured property, cancellation of debt, contributions to an individual retirement arrangement (IRA), and generally, payments other than interest and dividends, you are not required to sign the certification, but you must provide your correct TIN. See the instructions on page 4. Sign Here Signature of U.S. person ▶ Date ▶ General Instructions Section references are to the Internal Revenue Code unless otherwise noted. Purpose of Form A person who is required to file an information return with the IRS must obtain your correct taxpayer identification number (TIN) to report, for example, income paid to you, real estate transactions, mortgage interest you paid, acquisition or abandonment of secured property, cancellation of debt, or contributions you made to an IRA. Use Form W-9 only if you are a U.S. person (including a resident alien), to provide your correct TIN to the person requesting it (the requester) and, when applicable, to: 1. Certify that the TIN you are giving is correct (or you are waiting for a number to be issued), 2. Certify that you are not subject to backup withholding, or 3. Claim exemption from backup withholding if you are a U.S. exempt payee. If applicable, you are also certifying that as a U.S. person, your allocable share of any partnership income from a U.S. trade or business is not subject to the withholding tax on foreign partners’ share of effectively connected income. Note. If a requester gives you a form other than Form W-9 to request your TIN, you must use the requester’s form if it is substantially similar to this Form W-9. Definition of a U.S. person. For federal tax purposes, you are considered a U.S. person if you are: • An individual who is a U.S. citizen or U.S. resident alien, • A partnership, corporation, company, or association created or organized in the United States or under the laws of the United States, • An estate (other than a foreign estate), or • A domestic trust (as defined in Regulations section 301.7701-7). Special rules for partnerships. Partnerships that conduct a trade or business in the United States are generally required to pay a withholding tax on any foreign partners’ share of income from such business. Further, in certain cases where a Form W-9 has not been received, a partnership is required to presume that a partner is a foreign person, and pay the withholding tax. Therefore, if you are a U.S. person that is a partner in a partnership conducting a trade or business in the United States, provide Form W-9 to the partnership to establish your U.S. status and avoid withholding on your share of partnership income. Cat. No. 10231X Form W-9 (Rev. 12-2011) Page 2 Form W-9 (Rev. 12-2011) The person who gives Form W-9 to the partnership for purposes of establishing its U.S. status and avoiding withholding on its allocable share of net income from the partnership conducting a trade or business in the United States is in the following cases: • The U.S. owner of a disregarded entity and not the entity, • The U.S. grantor or other owner of a grantor trust and not the trust, and • The U.S. trust (other than a grantor trust) and not the beneficiaries of the trust. Foreign person. If you are a foreign person, do not use Form W-9. Instead, use the appropriate Form W-8 (see Publication 515, Withholding of Tax on Nonresident Aliens and Foreign Entities). Nonresident alien who becomes a resident alien. Generally, only a nonresident alien individual may use the terms of a tax treaty to reduce or eliminate U.S. tax on certain types of income. However, most tax treaties contain a provision known as a “saving clause.” Exceptions specified in the saving clause may permit an exemption from tax to continue for certain types of income even after the payee has otherwise become a U.S. resident alien for tax purposes. If you are a U.S. resident alien who is relying on an exception contained in the saving clause of a tax treaty to claim an exemption from U.S. tax on certain types of income, you must attach a statement to Form W-9 that specifies the following five items: 1. The treaty country. Generally, this must be the same treaty under which you claimed exemption from tax as a nonresident alien. 2. The treaty article addressing the income. 3. The article number (or location) in the tax treaty that contains the saving clause and its exceptions. 4. The type and amount of income that qualifies for the exemption from tax. 5. Sufficient facts to justify the exemption from tax under the terms of the treaty article. Example. Article 20 of the U.S.-China income tax treaty allows an exemption from tax for scholarship income received by a Chinese student temporarily present in the United States. Under U.S. law, this student will become a resident alien for tax purposes if his or her stay in the United States exceeds 5 calendar years. However, paragraph 2 of the first Protocol to the U.S.-China treaty (dated April 30, 1984) allows the provisions of Article 20 to continue to apply even after the Chinese student becomes a resident alien of the United States. A Chinese student who qualifies for this exception (under paragraph 2 of the first protocol) and is relying on this exception to claim an exemption from tax on his or her scholarship or fellowship income would attach to Form W-9 a statement that includes the information described above to support that exemption. If you are a nonresident alien or a foreign entity not subject to backup withholding, give the requester the appropriate completed Form W-8. What is backup withholding? Persons making certain payments to you must under certain conditions withhold and pay to the IRS a percentage of such payments. This is called “backup withholding.” Payments that may be subject to backup withholding include interest, tax-exempt interest, dividends, broker and barter exchange transactions, rents, royalties, nonemployee pay, and certain payments from fishing boat operators. Real estate transactions are not subject to backup withholding. You will not be subject to backup withholding on payments you receive if you give the requester your correct TIN, make the proper certifications, and report all your taxable interest and dividends on your tax return. Payments you receive will be subject to backup withholding if: 1. You do not furnish your TIN to the requester, 2. You do not certify your TIN when required (see the Part II instructions on page 3 for details), 3. The IRS tells the requester that you furnished an incorrect TIN, 4. The IRS tells you that you are subject to backup withholding because you did not report all your interest and dividends on your tax return (for reportable interest and dividends only), or 5. You do not certify to the requester that you are not subject to backup withholding under 4 above (for reportable interest and dividend accounts opened after 1983 only). Certain payees and payments are exempt from backup withholding. See the instructions below and the separate Instructions for the Requester of Form W-9. Also see Special rules for partnerships on page 1. Updating Your Information You must provide updated information to any person to whom you claimed to be an exempt payee if you are no longer an exempt payee and anticipate receiving reportable payments in the future from this person. For example, you may need to provide updated information if you are a C corporation that elects to be an S corporation, or if you no longer are tax exempt. In addition, you must furnish a new Form W-9 if the name or TIN changes for the account, for example, if the grantor of a grantor trust dies. Penalties Failure to furnish TIN. If you fail to furnish your correct TIN to a requester, you are subject to a penalty of $50 for each such failure unless your failure is due to reasonable cause and not to willful neglect. Civil penalty for false information with respect to withholding. If you make a false statement with no reasonable basis that results in no backup withholding, you are subject to a $500 penalty. Criminal penalty for falsifying information. Willfully falsifying certifications or affirmations may subject you to criminal penalties including fines and/or imprisonment. Misuse of TINs. If the requester discloses or uses TINs in violation of federal law, the requester may be subject to civil and criminal penalties. Specific Instructions Name If you are an individual, you must generally enter the name shown on your income tax return. However, if you have changed your last name, for instance, due to marriage without informing the Social Security Administration of the name change, enter your first name, the last name shown on your social security card, and your new last name. If the account is in joint names, list first, and then circle, the name of the person or entity whose number you entered in Part I of the form. Sole proprietor. Enter your individual name as shown on your income tax return on the “Name” line. You may enter your business, trade, or “doing business as (DBA)” name on the “Business name/disregarded entity name” line. Partnership, C Corporation, or S Corporation. Enter the entity's name on the “Name” line and any business, trade, or “doing business as (DBA) name” on the “Business name/disregarded entity name” line. Disregarded entity. Enter the owner's name on the “Name” line. The name of the entity entered on the “Name” line should never be a disregarded entity. The name on the “Name” line must be the name shown on the income tax return on which the income will be reported. For example, if a foreign LLC that is treated as a disregarded entity for U.S. federal tax purposes has a domestic owner, the domestic owner's name is required to be provided on the “Name” line. If the direct owner of the entity is also a disregarded entity, enter the first owner that is not disregarded for federal tax purposes. Enter the disregarded entity's name on the “Business name/disregarded entity name” line. If the owner of the disregarded entity is a foreign person, you must complete an appropriate Form W-8. Note. Check the appropriate box for the federal tax classification of the person whose name is entered on the “Name” line (Individual/sole proprietor, Partnership, C Corporation, S Corporation, Trust/estate). Limited Liability Company (LLC). If the person identified on the “Name” line is an LLC, check the “Limited liability company” box only and enter the appropriate code for the tax classification in the space provided. If you are an LLC that is treated as a partnership for federal tax purposes, enter “P” for partnership. If you are an LLC that has filed a Form 8832 or a Form 2553 to be taxed as a corporation, enter “C” for C corporation or “S” for S corporation. If you are an LLC that is disregarded as an entity separate from its owner under Regulation section 301.7701-3 (except for employment and excise tax), do not check the LLC box unless the owner of the LLC (required to be identified on the “Name” line) is another LLC that is not disregarded for federal tax purposes. If the LLC is disregarded as an entity separate from its owner, enter the appropriate tax classification of the owner identified on the “Name” line. Page 3 Form W-9 (Rev. 12-2011) Other entities. Enter your business name as shown on required federal tax documents on the “Name” line. This name should match the name shown on the charter or other legal document creating the entity. You may enter any business, trade, or DBA name on the “Business name/ disregarded entity name” line. Exempt Payee If you are exempt from backup withholding, enter your name as described above and check the appropriate box for your status, then check the “Exempt payee” box in the line following the “Business name/ disregarded entity name,” sign and date the form. Generally, individuals (including sole proprietors) are not exempt from backup withholding. Corporations are exempt from backup withholding for certain payments, such as interest and dividends. Note. If you are exempt from backup withholding, you should still complete this form to avoid possible erroneous backup withholding. The following payees are exempt from backup withholding: 1. An organization exempt from tax under section 501(a), any IRA, or a custodial account under section 403(b)(7) if the account satisfies the requirements of section 401(f)(2), 2. The United States or any of its agencies or instrumentalities, 3. A state, the District of Columbia, a possession of the United States, or any of their political subdivisions or instrumentalities, 4. A foreign government or any of its political subdivisions, agencies, or instrumentalities, or 5. An international organization or any of its agencies or instrumentalities. Other payees that may be exempt from backup withholding include: 6. A corporation, 7. A foreign central bank of issue, 8. A dealer in securities or commodities required to register in the United States, the District of Columbia, or a possession of the United States, 9. A futures commission merchant registered with the Commodity Futures Trading Commission, 10. A real estate investment trust, 11. An entity registered at all times during the tax year under the Investment Company Act of 1940, 12. A common trust fund operated by a bank under section 584(a), 13. A financial institution, 14. A middleman known in the investment community as a nominee or custodian, or 15. A trust exempt from tax under section 664 or described in section 4947. The following chart shows types of payments that may be exempt from backup withholding. The chart applies to the exempt payees listed above, 1 through 15. IF the payment is for . . . THEN the payment is exempt for . . . Interest and dividend payments All exempt payees except for 9 Broker transactions Exempt payees 1 through 5 and 7 through 13. Also, C corporations. Barter exchange transactions and patronage dividends Exempt payees 1 through 5 Payments over $600 required to be Generally, exempt payees reported and direct sales over 1 through 7 2 1 $5,000 1 2 See Form 1099-MISC, Miscellaneous Income, and its instructions. However, the following payments made to a corporation and reportable on Form 1099-MISC are not exempt from backup withholding: medical and health care payments, attorneys' fees, gross proceeds paid to an attorney, and payments for services paid by a federal executive agency. Part I. Taxpayer Identification Number (TIN) Enter your TIN in the appropriate box. If you are a resident alien and you do not have and are not eligible to get an SSN, your TIN is your IRS individual taxpayer identification number (ITIN). Enter it in the social security number box. If you do not have an ITIN, see How to get a TIN below. If you are a sole proprietor and you have an EIN, you may enter either your SSN or EIN. However, the IRS prefers that you use your SSN. If you are a single-member LLC that is disregarded as an entity separate from its owner (see Limited Liability Company (LLC) on page 2), enter the owner’s SSN (or EIN, if the owner has one). Do not enter the disregarded entity’s EIN. If the LLC is classified as a corporation or partnership, enter the entity’s EIN. Note. See the chart on page 4 for further clarification of name and TIN combinations. How to get a TIN. If you do not have a TIN, apply for one immediately. To apply for an SSN, get Form SS-5, Application for a Social Security Card, from your local Social Security Administration office or get this form online at www.ssa.gov. You may also get this form by calling 1-800-772-1213. Use Form W-7, Application for IRS Individual Taxpayer Identification Number, to apply for an ITIN, or Form SS-4, Application for Employer Identification Number, to apply for an EIN. You can apply for an EIN online by accessing the IRS website at www.irs.gov/businesses and clicking on Employer Identification Number (EIN) under Starting a Business. You can get Forms W-7 and SS-4 from the IRS by visiting IRS.gov or by calling 1-800-TAX-FORM (1-800-829-3676). If you are asked to complete Form W-9 but do not have a TIN, write “Applied For” in the space for the TIN, sign and date the form, and give it to the requester. For interest and dividend payments, and certain payments made with respect to readily tradable instruments, generally you will have 60 days to get a TIN and give it to the requester before you are subject to backup withholding on payments. The 60-day rule does not apply to other types of payments. You will be subject to backup withholding on all such payments until you provide your TIN to the requester. Note. Entering “Applied For” means that you have already applied for a TIN or that you intend to apply for one soon. Caution: A disregarded domestic entity that has a foreign owner must use the appropriate Form W-8. Part II. Certification To establish to the withholding agent that you are a U.S. person, or resident alien, sign Form W-9. You may be requested to sign by the withholding agent even if item 1, below, and items 4 and 5 on page 4 indicate otherwise. For a joint account, only the person whose TIN is shown in Part I should sign (when required). In the case of a disregarded entity, the person identified on the “Name” line must sign. Exempt payees, see Exempt Payee on page 3. Signature requirements. Complete the certification as indicated in items 1 through 3, below, and items 4 and 5 on page 4. 1. Interest, dividend, and barter exchange accounts opened before 1984 and broker accounts considered active during 1983. You must give your correct TIN, but you do not have to sign the certification. 2. Interest, dividend, broker, and barter exchange accounts opened after 1983 and broker accounts considered inactive during 1983. You must sign the certification or backup withholding will apply. If you are subject to backup withholding and you are merely providing your correct TIN to the requester, you must cross out item 2 in the certification before signing the form. 3. Real estate transactions. You must sign the certification. You may cross out item 2 of the certification. Page 4 Form W-9 (Rev. 12-2011) 4. Other payments. You must give your correct TIN, but you do not have to sign the certification unless you have been notified that you have previously given an incorrect TIN. “Other payments” include payments made in the course of the requester’s trade or business for rents, royalties, goods (other than bills for merchandise), medical and health care services (including payments to corporations), payments to a nonemployee for services, payments to certain fishing boat crew members and fishermen, and gross proceeds paid to attorneys (including payments to corporations). 5. Mortgage interest paid by you, acquisition or abandonment of secured property, cancellation of debt, qualified tuition program payments (under section 529), IRA, Coverdell ESA, Archer MSA or HSA contributions or distributions, and pension distributions. You must give your correct TIN, but you do not have to sign the certification. What Name and Number To Give the Requester For this type of account: Give name and SSN of: 1. Individual 2. Two or more individuals (joint account) The individual The actual owner of the account or, if combined funds, the first 1 individual on the account 3. Custodian account of a minor (Uniform Gift to Minors Act) The minor 4. a. The usual revocable savings trust (grantor is also trustee) b. So-called trust account that is not a legal or valid trust under state law 5. Sole proprietorship or disregarded entity owned by an individual 6. Grantor trust filing under Optional Form 1099 Filing Method 1 (see Regulation section 1.671-4(b)(2)(i)(A)) For this type of account: The grantor-trustee 7. Disregarded entity not owned by an individual 8. A valid trust, estate, or pension trust The owner 2 The actual owner The owner The grantor* Give name and EIN of: Legal entity 4 The corporation 13. Account with the Department of Agriculture in the name of a public entity (such as a state or local government, school district, or prison) that receives agricultural program payments 14. Grantor trust filing under the Form 1041 Filing Method or the Optional Form 1099 Filing Method 2 (see Regulation section 1.671-4(b)(2)(i)(B)) The public entity 2 3 1 3 9. Corporation or LLC electing corporate status on Form 8832 or Form 2553 10. Association, club, religious, charitable, educational, or other tax-exempt organization 11. Partnership or multi-member LLC 12. A broker or registered nominee 1 1 The organization The partnership The broker or nominee Note. If no name is circled when more than one name is listed, the number will be considered to be that of the first name listed. Secure Your Tax Records from Identity Theft Identity theft occurs when someone uses your personal information such as your name, social security number (SSN), or other identifying information, without your permission, to commit fraud or other crimes. An identity thief may use your SSN to get a job or may file a tax return using your SSN to receive a refund. To reduce your risk: • Protect your SSN, • Ensure your employer is protecting your SSN, and • Be careful when choosing a tax preparer. If your tax records are affected by identity theft and you receive a notice from the IRS, respond right away to the name and phone number printed on the IRS notice or letter. If your tax records are not currently affected by identity theft but you think you are at risk due to a lost or stolen purse or wallet, questionable credit card activity or credit report, contact the IRS Identity Theft Hotline at 1-800-908-4490 or submit Form 14039. For more information, see Publication 4535, Identity Theft Prevention and Victim Assistance. Victims of identity theft who are experiencing economic harm or a system problem, or are seeking help in resolving tax problems that have not been resolved through normal channels, may be eligible for Taxpayer Advocate Service (TAS) assistance. You can reach TAS by calling the TAS toll-free case intake line at 1-877-777-4778 or TTY/TDD 1-800-829-4059. Protect yourself from suspicious emails or phishing schemes. Phishing is the creation and use of email and websites designed to mimic legitimate business emails and websites. The most common act is sending an email to a user falsely claiming to be an established legitimate enterprise in an attempt to scam the user into surrendering private information that will be used for identity theft. The IRS does not initiate contacts with taxpayers via emails. Also, the IRS does not request personal detailed information through email or ask taxpayers for the PIN numbers, passwords, or similar secret access information for their credit card, bank, or other financial accounts. If you receive an unsolicited email claiming to be from the IRS, forward this message to phishing@irs.gov. You may also report misuse of the IRS name, logo, or other IRS property to the Treasury Inspector General for Tax Administration at 1-800-366-4484. You can forward suspicious emails to the Federal Trade Commission at: spam@uce.gov or contact them at www.ftc.gov/idtheft or 1-877-IDTHEFT (1-877-438-4338). Visit IRS.gov to learn more about identity theft and how to reduce your risk. The trust List first and circle the name of the person whose number you furnish. If only one person on a joint account has an SSN, that person’s number must be furnished. Circle the minor’s name and furnish the minor’s SSN. You must show your individual name and you may also enter your business or “DBA” name on the “Business name/disregarded entity” name line. You may use either your SSN or EIN (if you have one), but the IRS encourages you to use your SSN. 4 List first and circle the name of the trust, estate, or pension trust. (Do not furnish the TIN of the personal representative or trustee unless the legal entity itself is not designated in the account title.) Also see Special rules for partnerships on page 1. *Note. Grantor also must provide a Form W-9 to trustee of trust. Privacy Act Notice Section 6109 of the Internal Revenue Code requires you to provide your correct TIN to persons (including federal agencies) who are required to file information returns with the IRS to report interest, dividends, or certain other income paid to you; mortgage interest you paid; the acquisition or abandonment of secured property; the cancellation of debt; or contributions you made to an IRA, Archer MSA, or HSA. The person collecting this form uses the information on the form to file information returns with the IRS, reporting the above information. Routine uses of this information include giving it to the Department of Justice for civil and criminal litigation and to cities, states, the District of Columbia, and U.S. possessions for use in administering their laws. The information also may be disclosed to other countries under a treaty, to federal and state agencies to enforce civil and criminal laws, or to federal law enforcement and intelligence agencies to combat terrorism. You must provide your TIN whether or not you are required to file a tax return. Under section 3406, payers must generally withhold a percentage of taxable interest, dividend, and certain other payments to a payee who does not give a TIN to the payer. Certain penalties may also apply for providing false or fraudulent information. From: To: Subject: Date: Attachments: Beth L. Soliere Bob Stump Fwd: HEPG Advance Reading for Session Two Friday, October 07, 2016 10:11:02 AM DM Berkovitz CFTC Administrative Process FDLRv35#2 Mar-Apr 2015.pdf ATT00001.htm Begin forwarded message: From: "Mahoney, Jo-Ann" Date: October 7, 2016 at 9:44:30 AM MST To: "Mahoney, Jo-Ann" Cc: "Gill, Susan" Subject: HEPG Advance Reading for Session Two Dan Berkovitz has provided this article as background for our HEPG Thursday afternoon discussion on market manipulation cases.    REPORT Futures & Derivatives Law The Journal on the Law of Investment & Risk Management Products ARTICLE REPRINT March 2015 n Volume 35 n The Resurrection of CFTC Administrative Enforcement Proceedings: Efficient Justice or a Biased Forum? BY DAN M. BERKOVITZ The author is a partner in the law firm Wilmer, Cutler, Pickering, Hale and Dorr, LLP, and served as General Counsel of the CFTC from 2009-2013. Summary In the wake of the broad new enforcement authority provided to the Commodity Futures Trading Commission (“CFTC” or “Commission”) in the Dodd-Frank Reform and Consumer Protection Act (“Dodd-Frank”), and severe constraints on agency enforcement resources, the Director of the CFTC’s Division of Enforcement (“Division”) recently stated that the Division intends to increasingly rely on the CFTC’s administrative enforcement process, as opposed to filing a complaint in federal court, to prosecute violations of the Commodity Exchange Act (“CEA”).1 The Division Director explained that the “overwhelming reason for this change is [the agency’s lack of] resources,”2 including its “bandwidth for discovery-intense litigation,”3 but added that the administrative process would also allow the Commission to develop its expertise and the case law with respect to the new statute and regulations.4 The resurrection of the CFTC’s administrative enforcement process would depart from the CFTC’s recent approach to contested enforcement cases. For more than a decade the Division has filed con- tested cases exclusively in federal court— the last contested enforcement case filed before a CFTC administrative law judge (“ALJ”) was in 2001, when the Commission charged Anthony J. DiPlacido with manipulation and attempted manipulation of electricity futures contracts on five occasions in 1998.5 Although the Division has never publicly explained its rationale for avoiding the administrative process during this period, it is generally believed that the Division’s track record in its administrative forum as well as the higher profile of cases filed in federal court were key factors.6 Similar statements by Securities and Exchange Commission (“SEC”) officials signaling the SEC’s intent to rely more on the administrative enforcement process have provoked criticism that administrative proCONTINUED ON PAGE 3 Article REPRINT Reprinted from the Futures & Derivatives Law Report. Copyright © 2015 Thomson Reuters. For more information about this publication please visit legalsolutions.thomsonreuters.com Issue 2 March 2015 n Volume 35 n Issue 2 Futures & Derivatives Law Report © 2015 Thomson Reuters. This publication was created to provide you with accurate and authoritative information concerning the subject matter covered, however it may not necessarily have been prepared by persons licensed to practice law in a particular jurisdiction. The publisher is not engaged in rendering legal or other professional advice, and this publication is not a substitute for the advice of an attorney. If you require legal or other expert advice, you should seek the services of a competent attorney or other professional. For authorization to photocopy, please contact the Copyright Clearance Center at 222 Rosewood Drive, Danvers, MA 01923, USA (978) 750-8400; fax (978) 646-8600 or West’s Copyright Services at 610 Opperman Drive, Eagan, MN 55123, fax (651)687-7551. Please outline the specific material involved, the number of copies you wish to distribute and the purpose or format of the use. For subscription information, please contact the publisher at: west.legalworkspublications@thomson.com Editorial Board STEVEN W. SEEMER Publisher, West Legal Ed Center RICHARD A. MILLER Editor-in-Chief, Prudential Financial Two Gateway Center, 5th Floor, Newark, NJ 07102 Phone: 973-802-5901 Fax: 973-367-5135 E-mail: richard.a.miller@prudential.com MICHAEL S. SACKHEIM Managing Editor, Sidley Austin LLP 787 Seventh Ave., New York, NY 10019 Phone: (212) 839-5503 Fax: (212) 839-5599 E-mail: msackheim@sidley.com PAUL ARCHITZEL Wilmer Cutler Pickering Hale and Dorr Washington, D.C. CONRAD G. BAHLKE Strook & Strook & Lavan LLP New York, NY ANDREA M. CORCORAN Align International, LLC Washington, D.C. Futures & Derivatives Law Report West LegalEdcenter 610 Opperman Drive Eagan, MN55123 © 2015 Thomson Reuters W. IAIN CULLEN Simmons & Simmons London, England IAN CUILLERIER White & Case LLP New York WARREN N. DAVIS Sutherland Asbill & Brennan Washington, D.C. SUSAN C. ERVIN Davis Polk & Wardwell LLC Washington, D.C. RONALD H. FILLER New York Law School DENIS M. FORSTER New York, NY THOMAS LEE HAZEN University of North Carolina at Chapel Hill DONALD L. HORWITZ North American Derivatives Exchange Chicago, IL PHILIP MCBRIDE JOHNSON Washington, D.C. DENNIS KLEJNA New York, NY PETER Y. MALYSHEV Latham & Watkins Washington, D.C., and New York, NY ROBERT M. MCLAUGHLIN Fried, Frank, Harris, Shriver & Jacobson LLP New York, NY CHARLES R. MILLS K&L Gates, LLP Washington, D.C. DAVID S. MITCHELL Fried, Frank, Harris, Shriver & Jacobson LLP New York, NY RITA MOLESWORTH Willkie Farr & Gallagher New York, NY PAUL J. PANTANO Cadwalader, Wickersham & Taft LLP Washington, D.C. GLEN A. RAE Banc of America Merrill Lynch New York, NY KENNETH M. RAISLER Sullivan & Cromwell New York, NY KENNETH M. ROSENZWEIG Katten Muchin Rosenman Chicago, IL THOMAS A. RUSSO American International Group, Inc. New York, NY HOWARD SCHNEIDER Charles River Associates New York, NY LAUREN TEIGLAND-HUNT Teigland-Hunt LLP New York, NY PAUL UHLENHOP Lawrence, Kamin, Saunders & Uhlenhop Chicago, IL SHERRI VENOKUR Venokur LLC New York, NY For authorization to photocopy, please contact the Copyright Clearance Center at 222 Rosewood Drive, Danvers, MA 01923, USA (978) 750-8400; fax (978) 646-8600 or West’s Copyright Services at 610 Opperman Drive, Eagan, MN 55123, fax (651) 687-7551. Please outline the specific material involved, the number of copies you wish to distribute and the purpose or format of the use. This publication was created to provide you with accurate and authoritative information concerning the subject matter covered. However, this publication was not necessarily prepared by persons licensed to practice law in a particular jurisdication. The publisher is not engaged in rendering legal or other professional advice, and this publication is not a substitute for the advice of an attorney. If you require legal or other expert advice, you should seek the services of a competent attorney or other professional. Copyright is not claimed as to any part of the original work prepared by a United States Government officer or employee as part of the person’s official duties. One Year Subscription n 11 Issues n $820.00 (ISSN#: 1083-8562) 2 © 2015 THOMSON REUTERS Futures & Derivatives Law Report CONTINUED FROM PAGE 1 ceedings are inherently unfair due to the absence of the procedural rights that defendants have in federal court, and that an agency cannot both be a prosecutor and an unbiased judge based on the same underlying facts. “These in-house proceedings, which provide far less discovery than does litigation in federal courts and do not operate under the traditional rules of evidence, provide an undeniable ‘insider’ advantage to the SEC,” two critics wrote in a recent op-ed in the The Washington Post.7 Noting the SEC’s favorable track record in its recent administrative proceedings, U.S. District Court Judge Jed Rakoff cautioned that the SEC’s administrative process is “unlikely … to lead to as balanced, careful, and impartial interpretations as would result from having those cases brought in federal court.”8 Concerns regarding the fairness of the agency administrative enforcement process are not new. Shortly after the Commission was first established, former CFTC Chairman William T. Bagley wrote: An inherent and pervasive “undue process” exists at the CFTC and all comparable agencies when the Commission itself is a rule maker, policeman, grand jury, prosecutor, judge and jury with de novo powers in the same case at virtually the same time. The agency has “heard” your case at least three and perhaps more times before you have a hearing. The minds of men are simply not supple enough to judge a defendant’s culpability fairly when vindication of the Commission’s own prosecution and reputation are also at stake in an adversarial proceeding.9 This article first describes the Commission’s administrative process for contested enforcement cases, including noting where the Commission’s procedures are similar to or differ from those available in a federal court proceeding. This article then traces the CFTC’s use (and disuse) of the administrative enforcement process, from the time when the administrative process was the exclusive means available to the agency for prosecuting violations of the CEA, through the current period when the agency has forsaken the use of this process in contested enforcement proceedings. The agency’s prior experience with the administrative process indicates that despite the absence of discovery in agency proceedings, these proceedings can take years to resolve, particularly in cases involving complex © 2015 THOMSON REUTERS March 2015 n Volume 35 n Issue 2 factual and legal issues, such as cases involving allegations of manipulation. Moreover, rather than exhibiting any “home-court” advantage for the Division, the Commission’s decisions in these complex cases often failed to develop the law or make findings in accordance with the positions taken by the Division. Finally, the article examines the extent to which defendants in CFTC administrative proceedings may be able to challenge the fairness of administrative proceedings as well as the agency’s ability to use such proceedings to develop the law as the agency desires.10 Although the courts have traditionally afforded deference to administrative agency determinations in adjudicatory proceedings on questions within the agency’s area of expertise, a number of judges have recently questioned the wisdom of this doctrine, particularly as it applies to administrative legal interpretations made in enforcement actions. The more aggressively the CFTC attempts to use the administrative enforcement process to interpret and apply its new statutory authorities, the more likely that this traditional doctrine will be re-examined. The Administrative Enforcement Process The CFTC’s administrative enforcement authority is statutorily based in Section 6(c) of the CEA. If the Commission has “reason to believe that any person (other than a registered entity) is violating or has violated [the CEA], or any rule, regulation or order” promulgated thereunder, Section 6(c)(4) authorizes the Commission to serve a complaint upon that person, which “shall … contain a description of the charges against the person … [and] … a notice of hearing that specifies the date and location of the hearing regarding the complaint.”11 Section 6(c)(4) (C) authorizes the Commission to hold the hearing itself or to designate an ALJ to conduct the hearing. Section 6(c)(10) also authorizes the Commission to impose sanctions for violations. Based on the evidence received during the hearing, the Commission may prohibit a person from trading on a registered entity, suspend or revoke the registration of any person, or assess civil penalties for the violations, up to the maximum amounts specified in the statute.12 A person subject to any such sanctions imposed by the Commission may seek judicial review of the Commission’s determinations in the U.S. Court of Appeals. The Commission’s Rules of Practice for conducting adjudicatory hearings in enforcement actions are 3 March 2015 n Volume 35 n Issue 2 set forth in Part 10 of the Commission’s regulations. In accordance with CEA Section 6(c)(4)(B), an adjudicatory proceeding is commenced when the Division files a complaint and notice of hearing with the CFTC’s Office of Proceedings.13 The complaint must state the Commission’s legal authority and jurisdiction to conduct the hearing, and the alleged violations of law and the facts upon which the alleged violations are based with sufficient specificity so as to “permit a specific response to each allegation.”14 Following the service of the complaint and notice of a hearing, the respondent must file an answer as to whether the respondent admits, denies, or does not have and is unable to obtain sufficient information to admit or deny each allegation.15 The answer must include a statement of facts supporting each affirmative defense.16 The failure to file an answer within 20 days may result in a default judgment against the respondent.17 Upon the filing of a complaint the Commission’s Office of Proceedings will assign an ALJ to conduct a hearing. Until 2012, the Commission employed two full-time ALJs to conduct its adjudicatory hearings, which generally consisted of both enforcement cases and certain reparations cases involving claims for amounts greater than $30,000.18 In 2012, however, due to the declining adjudicatory caseload, the Commission eliminated its two full-time ALJs and determined it would use “borrowed, detailed or retired ALJs as needed to manage the proceedings formerly handled by the permanent ALJs.”19 The ALJ is responsible for the conduct of the proceeding. The ALJ may administer oaths and affirmations, issue subpoenas, receive relevant evidence and make evidentiary rulings, examine witnesses, hold pre-hearing conferences, and rule on all motions.20 ALJs are independent from the Division – they may not be responsible to or under the supervision of any person performing an investigatory or prosecutorial function.21 Similarly, an ALJ may not be advised by any person performing an investigatory or prosecutorial function with respect to the same or a factually related proceeding, except as witness or counsel.22 Ex parte communications are prohibited during an adjudicatory hearing.23 An ex parte communication is defined as an oral or written communication not on the public record with respect to which reasonable prior notice to all parties is not given. A party or other person that may be adversely affected by a proceeding may not make an ex parte communication that is relevant to the merits of the proceeding to any Commissioner, ALJ, or other Commission employee involved in the decisional process.24 4 Futures & Derivatives Law Report An ALJ may hold one or more pre-hearing conferences to determine the extent to which issues can be clarified, certain facts may be admitted or stipulated, documents authenticated, the number of witnesses limited, evidentiary objections considered, testimony filed, and the conduct of the hearing expedited.25 The ALJ also determines whether any other persons should be permitted to intervene in or be heard during the proceeding.26 Pre-hearing discovery under the Commission’s administrative process is more limited than in federal court under the Federal Rules of Civil Procedure (“Federal Rules”). Generally, although the Commission’s rules provide for each party to disclose to the other party or parties certain information regarding the legal theories and factual information upon which it intends to rely, respondents do not have a right to submit interrogatories or take the depositions of witnesses or potential witnesses, except in limited circumstances. Unlike a trial in federal court, where a party may have the opportunity to take the deposition of a witness prior to trial, the CFTC’s adjudicatory hearing may be the first—and only—opportunity for the respondent to examine a witness and the basis for the witness’s testimony. The Commission’s Rules of Practice require the parties to file a prehearing memorandum that discloses basic information about the case they intend to present. The prehearing memorandum must set forth an outline of the party’s case or defense; the legal theories upon which the party will rely; the identity and geographic location of each witness other than an expert witness, along with a brief summary of the witness’s expected testimony; and a list of documents that the party intends to introduce at the hearing, along with any copies thereof which the other parties do not already have and to which they do not have reasonably ready access.27 With respect to expert witnesses that a party intends to call, the party must identify each such witness and his or her qualifications, provide a list of any publications authored by the witness within the preceding ten years, a list of all cases in which the witness has testified as an expert within the preceding four years, a “complete statement of all opinions to be expressed by the witness and the basis or reasons for those opinions,” and a list of documents, data, or other written material considered by the witness in forming his or her opinion.28 The Division also must disclose certain information to the respondents prior to the hearing. The Division must make available and permit the respondents to make copies of all documents that were produced pursuant to subpoenas issued by the © 2015 THOMSON REUTERS Futures & Derivatives Law Report Division or otherwise obtained by the Division from persons outside the Commission; the subpoenas or other written requests for such documents; and all transcripts, investigative testimony and all exhibits to those transcripts.29 There are several exceptions to these disclosure requirements. The Division may withhold documents that would disclose the identity of a confidential source, confidential investigatory techniques or procedures. The Division may also withhold information that would disclose the market positions, business transactions, trade secrets, or names of customers of any persons other than the respondents, unless such information is relevant to the resolution of the proceeding.30 Information that is privileged from disclosure under other provisions of law also may be withheld.31 All parties have specific disclosure obligations with respect to witness statements.32 Each party must make available to the other party any statement in its possession of any person whom the party expects to call that relates to the anticipated testimony. This obligation covers transcripts of investigative interviews, depositions, trial or other testimony given by the witness, written statements signed by the witness, and substantially verbatim notes of interviews with the witness. The Division must produce witness statements prior to the scheduled hearing date, at a time designated by the ALJ. The respondent must produce its witness statements at the close of the Division’s case at the hearing. The ALJ, upon motion by any party, or upon his or her own initiative, may direct each party to serve upon the other parties a list of documents that they intend to introduce at the hearing. The ALJ may also then direct that each other party file and serve a response disclosing any objections to the authenticity or admissibility of such documents, along with the legal and factual grounds for such objections. After affording each party an opportunity to file briefs as to the authenticity or admissibility of the documents, the ALJ may rule as to whether the documents that are objected to shall be admitted.33 In contrast to the Federal Rules, which generally permit oral depositions or written interrogatories of any person, including parties, the CFTC’s Rules of Practice permit depositions or interrogatories only when a prospective witness will be unable to attend or testify at a hearing due to “age, illness, infirmity, imprisonment or on the basis that he is or will be outside of the United States at the time of the hearing”, the testimony is material, and “it is necessary to take his deposition in the interests of justice.”34 A party seeking to take the deposition of a witness must apply in writing to the ALJ for an order to take © 2015 THOMSON REUTERS March 2015 n Volume 35 n Issue 2 the deposition.35 A deposition may then be used at the hearing, provided that the witness is unable to testify at the hearing, the testimony was taken under oath, and the other parties had a reasonable opportunity to cross-examine the witness at the time the statement was made.36 Rule 10.68 authorizes any party to apply to the ALJ for the issuance of a subpoena requiring a person to testify at the hearing, or to produce “specified documentary or tangible evidence (subpoena duces tecum) at any designated time or place.”37 Another party may move to quash or limit the production, or for a protective order to limit the use or disclosure of such information. The ALJ may deny the application, or impose conditions upon the required production, if he or she considers the request “unreasonable, oppressive, excessive in scope, or unduly burdensome,” or may issue a protective order upon a showing of good cause.38 Although the ALJ may issue a subpoena to compel the attendance of a witness or the production of documents, the Commission does not have independent authority to impose sanctions for refusal to obey an administrative subpoena. Rather, the Commission may apply to federal court to order such person to appear before the ALJ or the Commission to provide testimony or produce documents, and the failure to obey such order of the court may lead to sanctions for contempt.39 Similar to the Federal Rules, however, the procedures for taking an oral deposition of a witness are the same as if the witness were testifying at the hearing. The witness is subject to both direct and cross-examination and the testimony shall be recorded verbatim. Objections to testimony, evidence or the conduct of the parties may be raised for a later ruling by the ALJ, and, if the parties agree, objections to matters testified to in the deposition may also be made at the hearing, even if the objection was not raised during the deposition.40 In order to narrow the issues to be determined at the hearing, prior to the hearing either party may request another party for “admission of the truth of any facts relevant to the pending proceeding.” If the other party objects, “the reasons therefor shall be stated.”41 With respect to the conduct of the hearing, the Rules of Practice provide that “Every party is entitled to due notice of hearings, the right to be represented by counsel, and the right to cross-examine witnesses, present oral and documentary evidence, submit rebuttal evidence, raise objections, make arguments and move for appropriate relief.”42 The ALJ may ensure that the evidence presented is relevant 5 March 2015 n Volume 35 n Issue 2 to the proceeding, and may limit cross-examination to the subject matter of the direct examination and matters affecting the credibility of the witness.43 Although Commission Rule 10.66(c) provides the ALJ with discretion to permit cross-examination as to any matter that is relevant to the issues in the proceeding, without regard to the scope of direct examination,44 the Commission has indicated this should be the exception rather than the rule. In upholding ALJ rulings limiting the scope of cross-examination, the Commission has approvingly referenced Federal Rule of Evidence 611(b), stating that “[c]rossexamination should be limited to the subject matter of the direct examination and matters affecting the credibility of the witness.”45 Commission Rule 10.67 provides a broad standard for the admissibility of evidence: “Relevant, material, and reliable evidence shall be admitted. Irrelevant, immaterial, unreliable and unduly repetitious evidence shall be excluded.”46 A party that objects to the introduction of evidence must “timely and briefly” state the grounds for the objection. Although the Commission is not bound to follow the Federal Rules of Evidence in its adjudicatory hearings, it nonetheless looks to the Federal Rules of Evidence as “guidance and support” in determining whether certain evidence is admissible.47 Thus, for example, the Commission has followed Federal Rule of Evidence 701 with respect to the admissibility of the opinion of a lay witness,48 and Federal Rule of Evidence 702 with respect to the testimony of an expert witnesses.49 The Commission also has adopted the “Brady rule,” which imposes a duty upon the Division to provide to the respondent “all material of which it aware that is arguably exculpatory as to either guilt or punishment.”50 Interlocutory review by the Commission of an ALJ’s ruling is available only in “extraordinary circumstances.”51 Circumstances in which the Commission, in its discretion, may grant interlocutory review include appeals from an adverse ruling on a motion to disqualify an ALJ, appeals from rulings suspending an attorney or denying intervention or limited participation, and appeals from rulings requiring the appearance of a Commission or other government agency employee or the production of Commission records.52 The Commission may also consider interlocutory review where the ALJ certifies to the Commission that the ruling sought to be appealed involves a controlling question of law or policy, immediate appeal may materially advance the ultimate resolution of the issues, and subsequent reversal of the ruling would cause unnecessary delay or expense to the parties.53 6 Futures & Derivatives Law Report Following the conclusion of the hearing, the parties may file proposed findings of fact and conclusions of law, as well as supporting briefs. Oral argument also may be held at the discretion of the ALJ. After the parties have filed their proposed findings of fact, conclusions of law, and supporting briefs, the ALJ will issue his or her initial decision, which is to be based on the record of the proceeding.54 In order to prevail, the Division must demonstrate that the charges “are supported by the weight of the evidence.”55 The “weight of the evidence” standard is equated with the “preponderance of the evidence” standard – i.e., a finding of liability must be supported by the preponderance of the evidence.56 Any party may appeal an ALJ decision, dismissal, or other final disposition to the Commission.57 The Commission also may determine to review an initial decision on its own initiative.58 The Commission ordinarily will consider the whole record on review, but may limit the issues to those presented in the briefs for appeal.59 In reviewing a matter on appeal, the Commission will determine sanctions de novo rather than defer to the assessment of the ALJ.60 The Commission also may choose to grant a motion to hold oral argument.61 If neither party appeals the initial decision or order and the Commission does not undertake review on its own initiative or stay the decision, then the decision becomes final 30 days after it is issued.62 If the proceeding results in an order for the imposition of a civil penalty, the suspension of trading privileges, or the suspension or revocation of a registration, a person may seek judicial review of the order in the U.S. Court of Appeals.63 CFTC Use of the Administrative Process From the passage of the Commodity Exchange Act in 1936 to the passage of the Commodity Futures Trading Commission Act in 1974 (“1974 Act”), which replaced the Commodity Exchange Authority within the Department of Agriculture with the independent, five-member Commission to administer and enforce the CEA, the administrative process was the only avenue for the agency to bring civil actions for violations of the CEA. During this period, the suspension or revocation of a person’s trading privileges on a designated contract market was the sole sanction available to the agency for civil violations of the CEA by non-exchange personnel. The 1974 Act authorized the Commission to impose civil penalties for violations of the CEA through its administrative proceedings and to bring actions © 2015 THOMSON REUTERS Futures & Derivatives Law Report in federal court to enjoin violations.64 The 1974 Act, however, did not provide the federal courts with authority to impose civil penalties for past violations. That authority remained solely with the Commission until 1992, when Congress amended the CEA to authorize the Commission to seek and for the courts to impose “upon a proper showing,” in actions brought by the Commission under Section 6c for injunctive relief, civil penalties for violations of the CEA.65 Thus, only within the past twenty years has the Division had the ability to choose which forum—administrative or judicial—in which to pursue civil penalties for violations of the CEA. Initially, therefore, the law of manipulation was developed through judicial review of administrative cases involving suspensions of trading privileges. In these early judicial cases, such as General Foods Corp. v. Brannan,66 Great Western Food Distributors, Inc. v. Brannan,67 Volkart Bros., Inc. v. Freeman,68 and Cargill, Inc. v. Hardin,69 the courts interpreted the CEA de novo – without according the agency’s position any particular deference. These judicial decisions did not always reach the result or produce the legal standard for manipulation sought by the agency. For example, in General Foods Corp. v. Brannan, the court held, contrary to the agency’s position, that the respondents’ large purchases of rye for the purpose of stabilizing the market did not constitute an unlawful attempt to manipulate or corner the market. The court stated that “the common criteria usual in manipulation or corner cases are deceit, trickery through the spreading of false rumors, concealment of position, the violation of express anti-manipulation controls, or other forms of fraud. None of these elements are claimed or shown to exist in the instant situation.”70 In Volkart, the Fifth Circuit held that a trader’s exploitation of a natural squeeze or corner would not constitute manipulation: “In brief, before the order punishing the petitioners can be sustained, it must appear not only that they profited from a squeeze, but that they intentionally brought about the squeeze by planned action.”71 After the agency sought unsuccessfully to have the Volkart ruling overturned through legislation, it turned to the administrative process to reconcile the conflicting judicial precedents and set forth its view of the appropriate standard.72 In 1977, in In re Hohenberg Bros., the Commission established the two elements of attempted manipulation: “An attempted manipulation requires only an intent to affect the market price of the commodity and some overt act in furtherance of that intent.”73 The Commission © 2015 THOMSON REUTERS March 2015 n Volume 35 n Issue 2 also held that a dominant or controlling position in the market is not a prerequisite for manipulation or attempted manipulation, nor is a profit motive.74 Several years later, in 1982, in In the Matter of Indiana Farm Bureau Coop. Ass’n, the Commission elaborated on the element of intent necessary to support a finding of manipulation. “It must be proven,” the Commission wrote, “that the accused acted (or failed) to act with the purpose or conscious object of causing or effecting a price or price trend in the market that did not reflect the legitimate forces of supply and demand influencing futures prices in the particular market at the time of the alleged manipulative activity.”75 The Commission approvingly cited the holdings in both General Foods and Volkart, stating that it is permissible for traders to seek the best price, even in a congested market, “as long as their trading activity does not have as its purpose the creation of ‘artificial’ or ‘distorted’ prices.” The Commission thus held that where a squeeze arises from natural conditions, and is not intentionally created by a long, “manipulative intent may not be inferred where a long does not exacerbate the congestion itself.”76 In 1987, in In the Matter of Cox, the Commission reviewed both the judicial and administrative precedents and set forth the four-part test that has become the standard for finding manipulation under CEA Section 9(a)(2): (1) that the accused had the ability to influence market prices; (2) that they specifically intended to do so; (3) that artificial prices existed; and (4) that the accused caused the artificial prices.77 The four-part test has been viewed by many as creating an insurmountable hurdle for the Division of Enforcement in proving a manipulation case, largely due to the difficulty in demonstrating the existence of artificial prices and causality.78 As a result of these concerns regarding the four-part test, in the Dodd-Frank Act Congress amended CEA Section 6(c) to also prohibit the use of “any manipulative or deceptive device or contrivance,” based on similar language in Section 10(b) of the Securities and Exchange Act of 1934. Although the Commission’s new anti-manipulation authority has yet to be tested, either in federal court or before the agency, it is widely believed that, based on the precedents interpreting similar language in the securities laws, it will be easier for the Division to meet its burden of proof under the SEC-based standard than under the precedents governing CEA Section 9(a)(2). The last contested case that the Division brought before an administrative judge was In the Matter of Anthony J. DiPlacido, which was filed in 2001, 7 March 2015 n Volume 35 n Issue 2 and concerned manipulative conduct occurring in 1998. Since the early 2000s, the Commission has filed all of its contested enforcement cases in federal court. Because these cases are filed in federal court under Section 6c of the CEA, they have sought both injunctive and other equitable relief as well as the imposition of civil penalties. 79 Despite the general impression that the administrative enforcement process proceeds much more quickly than federal court litigation due to the absence of pre-hearing discovery, the CFTC’s previous experience indicates that the administrative process can be lengthy, particularly in complex cases involving detailed factual issues and significant legal issues. A 1995 study by the General Accounting Office on administrative enforcement cases before the agency during the years 1989 through 1993 found that it took an average of 24 months from issuance of complaint and notice of hearing to initial decision, and then another 24 months from initial decision to appeal decision.80 Complex cases have taken significantly longer. The Commission issued its opinion in the DiPlacido case approximately 7 years after the complaint was filed. Other contested major manipulation cases brought before the agency in the 1970s and 1980s also took many years to resolve: Hohenberg took 6 years, In the Matter of Abrams took 7 years, Indiana Farm Bureau 8 years, and Cox 16 years.81 Moreover, with the exception of the DiPlacido case, in each of these other lengthy manipulation cases the Commission either dismissed or affirmed the ALJ’s dismissal of the complaint. At least with respect to the complex manipulation cases that the Commission has faced in the past, the record does not support either the view that the administrative process quickly or efficiently resolves such cases or that the Division of Enforcement enjoys any particular “home court” advantage when bringing a complex case to the Commission through the adjudicatory process.82 Judicial Review Administrative Procedures The courts have generally rejected due process challenges to the particular administrative procedures used by the CFTC in its adjudications. The courts have held that the CFTC must provide the basic requirements of due process—such as timely notice, an opportunity to be heard before an impartial judge, and an opportunity for cross-examination— but have refused to require the same procedures that 8 Futures & Derivatives Law Report are available in a federal court proceeding, or even to second-guess the particular procedures employed by the agency. In Silverman v. CFTC, the Seventh Circuit Court of Appeals rejected the claim that the failure to permit discovery was a denial of due process.83 “There is no basic constitutional right to pretrial discovery in administrative proceedings,” the court stated. “The Administrative Procedure Act contains no provision for pretrial discovery in the administrative process … and the Federal Rules of Civil Procedure for discovery do not apply to administrative proceedings.”84 The court noted, however, that the due process clause “does insure the fundamental fairness of the administrative hearing,” which includes a “fair trial, conducted in accordance with fundamental principles of fair play and applicable procedural standards established by law.”85 In Gimbel v. CFTC, the Seventh Circuit elaborated that due process requires both timely notice and a meaningful opportunity to be heard, but found that the instant case Commission’s adjudicatory hearing process had provided both.86 The Ninth Circuit also has ruled “‘there is no basic constitutional right to pretrial discovery in [Commission] proceedings.’”87 The Commission’s procedural discretion is not without limits. In Lloyd Carr & Co. v. CFTC, the ALJ refused to reopen the hearing to permit the testimony of a witness who was delayed due to a snowstorm and arrived at the hearing one minute late.88 The Second Circuit held that “Although an ALJ has wide latitude in the conduct of a hearing … administrative convenience or even necessity cannot override the constitutional requirements of due process.”89 The court found “the ALJ abused his discretion in failing to reopen the hearing when the first witness arrived one minute after the hearing was closed.”90 Hence, although the agency has substantial discretion as to the procedures to be used in the conduct of an administrative hearing, courts may step in where the agency’s procedures may affect the fundamental fairness of the proceeding. Findings of Fact Prior to the passage of the Dodd-Frank Act, the CEA included a standard for judicial review of factual findings in enforcement cases. Section 6(c) provided that “the findings of the Commission as to the facts, if supported by the weight of the evidence, shall [be] conclusive.”91 The courts interpreted this standard to be upheld the Commission’s findings must be supported by “the weight—or preponderance—of the evidence.”92 The courts also generally © 2015 THOMSON REUTERS Futures & Derivatives Law Report followed the elaboration of this standard that the Seventh Circuit set forth in Great Western Foods: [T]he function of this court is something other than that of mechanically reweighing the evidence to ascertain in which direction it preponderates; it is rather to review the record with the purpose of determining whether the finder of fact was justified, i.e. acted reasonably, in concluding that the evidence, including the demeanor of the witnesses, the reasonable inferences drawn therefrom and other pertinent circumstances, supported his findings.93 In the Dodd-Frank Act, Congress amended CEA Section 6(c) by including the new fraud-based antimanipulation authority and reorganizing the statutory language regarding the administrative enforcement process from one long paragraph into eleven subsections. Congress did not include in the revised section the previous language establishing the standard of review. Thus, CEA Section 6(c) no longer contains an explicit standard of judicial review for Commission factual findings. It is not clear, however, that the deletion of the “weight of the evidence” standard from CEA Section 6(c) will change the approach of the courts in reviewing agency findings of fact. In the absence of an explicit standard of review within the CEA, a court would likely turn to the standard of review in the Administrative Procedure Act (“APA”) that applies to agency on-the-record adjudications. With respect to factual determinations, Section 706 of the APA provides that “The reviewing court shall … hold unlawful and set aside agency action, findings, and conclusions found to be … (E) unsupported by substantial evidence … or otherwise reviewed on the record of an agency hearing provided by statute … .”94 APA caselaw indicates that the “substantial evidence” standard is distinct from the “weight of the evidence” standard. For example, the D.C. Circuit has stated that substantial evidence under Section 706 can be “something less than the weight of the evidence… . At a minimum however a decision is not supported by substantial evidence unless there is ‘such relevant evidence as a reasonable mind might accept as adequate to support a conclusion.’”95 This articulation of the “substantial evidence” standard of review in the APA does not appear to significantly differ from the standard of review articulated in Great Western Foods and other CFTC © 2015 THOMSON REUTERS March 2015 n Volume 35 n Issue 2 cases, where the courts have declined to reweigh the evidence themselves in order to determine where the preponderance lies, but rather will “review the record with the purpose of determining whether the finder of fact was justified, i.e. acted reasonably, in concluding that the evidence . . supported his findings.”96 There is no indication that Congress intended the deletion of the explicit “weight of the evidence” standard for judicial review in Section 6(c) to affect the burden of proof in the underlying proceedings. Thus, presumably, the Commission still must determine that the weight or preponderance of the evidence supports a finding of liability, and that these findings will continue to be reviewed by the courts for reasonableness. Sanctions The courts will generally review sanctions imposed by the Commission within its authority “only for an abuse of discretion, asking whether [the sanction] is rationally related to the offense.”97 Under this standard, “as long as an agency has ‘articulate[d] a satisfactory explanation for its action including a ‘rational connection between the facts found and the choice made’ … [the court] will uphold its choice of sanctions.”98 Questions of Law In DiPlacido, the Second Circuit set forth the standard of review for legal issues commonly used by the courts of appeal: “Our review of the Commission’s legal judgments is plenary,” but the court also stated that under the doctrine announced by the Supreme Court in Chevron U.S.A., Inc. v. Natural Res. Defense Council it would defer to the agency’s judgments within its area of expertise: “[W]here a question implicates Commission expertise, we defer to the Commission’s decision if it is reasonable.”99 Not all judges have enthusiastically embraced this deferential standard. In Elliott v. CFTC, the Seventh Circuit set forth what it termed two standards of review.100 “If the question presented is ‘of the sort that courts commonly encounter, de novo review is proper.’ … On the other hand, if the Commission’s decision was peculiarly within its area of expertise, we apply a deferential standard and will affirm so long as the decision is reasonable.” The court cautioned, however, that determining which standard to apply to a particular question is “no easy matter,” and that courts “should not automatically abandon heightened review” simply because the matter is within the agency’s expertise. “When the agency 9 March 2015 n Volume 35 n Issue 2 diet is food for the courts on a regular basis, there is little reason for judges to subordinate their own competence to administrative expertness.” Noting that courts “have applied the deferential standard to Commission determinations of the evidence necessary to prove violations of the [CEA] … as well as Commission rules,” the court found that the question of the whether the conduct at issue constituted non-competitive trading on the Chicago Board of Trade was appropriately within the agency’s area of expertise rather than the court’s, and accorded the agency’s determination deference.101 Writing in dissent, Judge Easterbrook scoffed at the notion that the Commission had any special expertise to decide this type of issue. “Ever since Congress began to establish independent agencies in 1887, it has been customary to refer to a commission’s ‘expertise.’ This is a figure of speech, an honorific, rather than a description of commissioners’ backgrounds and skills. It would be more accurate to call commissioners of the CFTC (and other agencies) ‘specialists.’ … Only one of the four Commissioners who participated in the order under review had any experience in the trading pits, and he dissented from the decision under consideration.”102 Judge Easterbrook’s challenge to the notion of Commission “expertise” that should trigger a more deferential standard of review in administrative enforcement cases reflects an unease with deferring to an administrative agency in the adjudicatory context that is similar to Judge Rakoff’s recent criticisms of the administrative enforcement process as a means for the development and interpretation of the law. Other judges have expressed a similar concern. U.S. District Judge Lewis Kaplan, also of the Southern District of New York, recently noted the concern that application of Chevron deference to the SEC’s interpretations of the securities laws in administrative proceedings will “increase the role of the Commission in interpreting the securities laws to the detriment or exclusion of the long standing interpretive role of the courts.”103 “These concerns are legitimate,” Judge Kaplan wrote, “whether born of self-interest or of a person assessment of whether the public interest would be served best by preserving the important interpretive role of Article III courts in construing the securities laws – a role the courts have performed since 1933.”104 Supreme Court Justice Eugene Scalia also recently expressed concerns regarding the doctrine of deference as it applies to executive branch interpretations of statutes that contemplate both criminal and civil enforcement. Writing in dissent to the denial of certiorari in Whitman v. United 10 Futures & Derivatives Law Report States, Justice Scalia disputed the notion that any deference should apply to executive branch interpretations of criminal statutes: “The rule of lenity requires interpreters to resolve ambiguities in criminal laws in favor of defendants,” Justice Scalia stated, as well as “vindicates the principle that only the legislature may define crimes and fix punishments. Congress cannot, throughout ambiguity, effectively leave that function to the courts—much less to the administrative bureaucracy.”105 Justice Scalia’ expansive language indicates he that he is questioning not only the doctrine of deference as it applies to criminal statutes, but also to administrative enforcement of laws that can be enforced either civilly or criminally. Justice Scalia concluded his dissent by stating he would be receptive to granting certiorari “when a petition properly presenting the question comes before us.”106 Hence, although the courts have typically granted deference to the Commission’s legal judgments within its area of expertise, a number of judges may be reluctant to apply the doctrine in circumstances—such as in the adjudicatory rather than rulemaking context—where they believe the courts are at least as well-suited to interpret and apply the law as the agency. In light of these concerns, it is by no means a foregone conclusion that the Commission will continue to be afforded Chevron deference in cases involving aggressive interpretations or applications of the Dodd-Frank law made in the course of agency adjudications. Conclusion The agency’s prior experience with the administrative enforcement process indicate that, despite the absence of discovery for litigants, it could take many years to resolve complex contested cases. Further, the Commission’s decisions in contested manipulation cases often did not produce the results desired by the Division of Enforcement. However, many of these cases occurred several decades ago. It has been well over a decade since the Division of Enforcement sought to litigate a contested enforcement case through the agency’s administrative hearing process. If the Division indeed resurrects the administrative enforcement process for contested cases, the Commission and interested parties in the agency’s administrative proceedings will have an opportunity to raise anew issues concerning appropriate hearing procedures, standards of proof, and the scope and role of judicial review. © 2015 THOMSON REUTERS Futures & Derivatives Law Report NOTES 1. Jean Eaglesham, CFTC Turns Toward Administrative Judges, Wall St. J., Nov. 9, 2014. 2. Id. 3. Stephanie Russell-Kraft, Cash-Strapped CFTC Faces Troubled Return To Admin Court, Law360, Nov. 14, 2014. 4. Stephanie Russell-Kraft , CFTC Plans More Administrative Actions, Criminal Crackdowns, Law360, Nov. 7, 2014. (“We have a host of new provisions under Dodd-Frank that need to have a precedent developed.”). 5. In the Matter of Anthony J. DiPlacido, Comm. Fut. L. Rep. (CCH) P30,970 (CFTC, Nov. 5, 2008). 6. See, e.g., Michael Schroeder, If You’ve Got a Beef With a Futures Broker, This Judge Isn’t For You—In Eight Years at the CFTC, Levine Has Never Ruled in Favor of an Investor, Wall St. J., Dec. 13, 2000. 7. Mark Cuban and Thomas Melsheimer, It is time to rein in the SEC, Washington Post, Dec. 19, 2014. 8. Judge Jed S. Rakoff, Is the S.E.C. Becoming a Law Unto Itself?, PLI Securities Regulation Institute Keynote Address, Nov. 5, 2014 (“the S.E.C. won 100% of its internal administrative hearings in the fiscal year ended September 30, 2014, whereas it won only 61% of its trials in federal court during the same period.”). 9. William T. Bagley, Introduction: A New Body of Law in an Era of Industry Growth, 27 Emory L.J. 849, 851 (1978). 10. For a discussion of constitutional issues raised in connection with administrative enforcement proceedings, including the use of ALJs to adjudicate cases, see Geoffrey F. Aronow, Back to the Future: The Use of Administrative Proceedings at the CFTC and SEC, 35 Futures and Derivatives L. Rep. 1 (Jan./Feb. 2015). 11. CEA §6(c)(4), 7 U.S.C. §9(4) (2014). 12. CEA §6(c)(10), 7 U.S.C. §9(10) (2014). 13. 17 C.F.R. §10.21. 14. 17 C.F.R. §10.22(a). The complaint also must notify the respondent of its right to a hearing and specify the time required under Regulation 10.23 for filing an answer. Regulation 10.22 also specifies the manner of service of process for the complaint. Regulation 10.12 specifies the service and filing requirements for filings subsequent to the complaint. 15. A statement of lack of information has the same effect as a denial; any allegation not expressly denied shall be deemed to be admitted. 17 C.F.R. §10.23(b)(1). 16. 17 C.F.R. § 10.23(b)(2). 17. 17 C.F.R. §10.23(c). © 2015 THOMSON REUTERS March 2015 18. 19. 20. 21. 22. 23. 24. 25. 26. 27. 28. 29. 30. 31. 32. n Volume 35 n Issue 2 17 C.F.R. § 12.26(c) (2009); CFTC, President’s Budget and Performance Plan, Fiscal Year 2013 60 (Feb. 2012). Id. 17 C.F.R. § 10.8. 17 C.F.R. § 10.9(a) 17 C.F.R. § 10.9(b). This prohibition does not apply to the members of the Commission. 17 C.F.R. § 10.10. Similarly, a Commissioner, ALJ, or other Commission employee involved in the decisional process may not make to any interested person outside the Commission an ex parte communication that is relevant to the merits of the proceeding. Regulation 10.10 also specifies procedures for the handling of ex parte communications, including providing notice to all parties in the proceeding, placing the communication in the public record of the proceeding, and potential sanctions for knowing violations of the prohibition. 17 C.F.R. § 10.41. Any person whose interests may be affected substantially by the proceeding may petition the ALJ to intervene as a party to the proceeding. To grant a petition to intervene as a party the ALJ must determine: (1) a substantial interest of the person seeking to intervene may be adversely affected by the proceeding; (2) the intervention will not materially prejudice the rights of any party; (3) participation as a party is otherwise consistent with the public interest; and (4) that leave to be heard would be inadequate to protect the person’s interest. 17 C.F.R. § 10.33. 17 C.F.R. § 10.42(a)(1). A party must also provide any such documents, data, or other written information that the other parties do not already have in their possession and to which they do not have reasonably ready access 17 C.F.R. § 10.42(a)(2). These procedures in Regulations 10.42(a)(1) and 10.42(a)(2) are not applicable to rebuttal evidence. 17 C.F.R. § 10.42(a)(3). 17 C.F.R. § 10.42(b)(1). The Division may also withhold information obtained from a domestic or foreign governmental entity or from a foreign futures authority that is either not relevant to the proceeding or that was provided on the condition that it not be disclosed or that it be disclosed only by the Commission or a representative of the Commission as evidence in an enforcement or other proceeding. 17 C.F.R. § 10.42(b)(2). 17 C.F.R. § 10.42(b)(3). 17 C.F.R. § 10.42(c). The Division’s obligations to produce witness statements under Rule 10.42(c) “generally accords with Rule 26.2 of the Federal Rules of Criminal Procedure, which 11 March 2015 33. 34. 35. 36. 37. 38. 39. 40. 41. 42. 43. 44. 45. 46. 47. 12 n Volume 35 n Issue 2 places in the Federal Rules the substance of the Jenks Act, 18 U.S.C. 3500.” Rules of Practice, 63 Fed. Reg. 55784, 55787 (Oct. 19, 1988). Under “the rule set forth in Jencks v. United States, 353 U.S. 657 (1957) and codified in 18 U.S.C. § 3500 (1994) … a criminal defendant ‘is entitled to relevant and competent reports and statements in possession of the Government touching the events and activities as to which a Government witness has testified at the trial.’ First Guaranty, [1980-1982 Transfer Binder] P 27,258 at 46,102.” In the Matter of Schiller and Chesrow, Comm. Fut. L. Rep. (CCH) P29,141, (CFTC, Sept. 3, 2002). 17 C.F.R. § 10.42(f). The Commission’s Rule 10.42(f) is modeled after Federal Rule of Civil Procedure 26(a)(3)(C). Rules of Practice, supra, at 55,787. 17 C.F.R. § 10.44(a). The application must include: (1) the name and address of the witness; (2) the specific matters concerning which the witness is expected to testify and their relevance; (3) the reasons why the deposition should be taken, supported by affidavits and a physician’s certificate, where appropriate; (4) the time when, the place where, and the person before whom the deposition will be taken; (5) a specification of the documents any materials which the deponent is expected to produce; and (6) application for any subpoena.. 17 C.F.R. § 10.44(b). 17 C.F.R. § 10.44(f)-(g) (2014); In the Matter of Global Minerals & Metals Corp., et al., Comm. Fut. L. Rep. (CCH) P29,555 (CFTC, Aug. 4, 2003). 17 C.F.R. § 10.68(a). The requesting party must show the general relevance of the testimony or evidence being sought. 17 C.F.R. § 10.68(c). In determining whether to grant a protective order, the ALJ “shall weigh the harm resulting from disclosure against the benefits of disclosure.” CEA §§ 6(c)(5)-(9), 7 U.S.C. §§ 9(5)-(9) (2014). 17 C.F.R. § 10.44(e), (f). 17 C.F.R. § 10.42(e). 17 C.F.R. § 10.66 (b). Id. 17 C.F.R. § 10.66(c). In re Reddy, Comm. Fut. L. Rep. (CCH) P27,271 (CFTC, Feb. 4, 1998), quoted approvingly in In the Matter of Anthony J. DiPlacido, supra note 5. In Reddy, the Commission also stated, “a party is guaranteed only ‘an opportunity for effective cross-examination,’ and the trier of fact may properly exercise discretion to impose reasonable limits on the scope of cross-examination.” (additional citations omitted). 17 C.F.R. § 10.67(a). In the Matter of Anthony J. DiPlacido, supra note 6. Futures & Derivatives Law Report 48. 49. 50. 51. 52. 53. In the Matter of Zuccarelli, Comm. Fut. L. Rep. (CCH) P27,597 (CFTC, Apr. 15, 1999) (“With respect to the opinion of a lay witness, we are guided by Federal Rule of Evidence 701 … .”). Rule 701 provides: “If the witness is not testifying as an expert, the witness’ testimony in the form of opinions or inferences is limited to those opinions or inferences which are (a) rationally based on the perception of the witness and (b) helpful to a clear understanding of the witness’ testimony or the determination of a fact in issue.” In the Matter of Brian W. Ray, Comm. Fut. L. Rep. (CCH) P41,914 (CFTC, Feb 18, 2011) (“As an administrative agency, the Commission is not bound by the Federal Rules of Evidence as to the admissibility of expert witnesses … Nevertheless, the Commission has considered those rules for guidance in determining whether certain evidence is admissible… . Under those rules, expert testimony must be both reliable and relevant. To be reliable, ‘ the reasoning or methodology underlying the testimony [must be] scientifically valid.’ Daubert v. Merrell Dow Pharmaceuticals, Inc., 509 U.S. 579, 5923 (1993). To be relevant, the evidence must be applicable ‘to the facts in issue.’ Id. at 593.”). See also In re Ashman, Comm. Fut. L. Rep. (CCH) P27,336 (CFTC, Apr. 22, 1998) (citing Fed. R. Evid. 702 and stating expert witness testimony is permitted when it “will assist the trier of fact to understand the evidence or to determine a fact in issue”). In the Matter of First Guaranty Metals, Comm. Fut. L. Rep. (CCH) P21,074 (CFTC, Jul. 2, 1980). In First Guaranty Metals, the Commission explained that the Brady rule “is not a discovery rule rather it is a rule of fairness and minimum prosecutorial obligation” and therefore a matter of due process. See also In the Matter of Bilello, Comm. Fut. L. Rep. (CCH) P27,345 (CFTC, Apr. 23, 1998); Brady v. Maryland, 373 U.S. 83 (1963). Although the Supreme Court has not ruled on whether the Brady rule applies to civil cases, Demjanjuk v. Petrovsky, 10 F.3d 338, 353 (6th Cir. 1993), four other federal agencies—the SEC, the Federal Maritime Commission, the Federal Deposit Insurance Commission, and the Federal Energy Regulatory Commission—also follow the Brady rule, although not in an identical manner. See Note, Hold Fast the Keys to the Kingdom: Federal Administrative Agencies and the Need for Brady Disclosure, 95 Minn. L. Rev. 1424, 1425 (2011). 17 C.F.R. § 10.101. See, e.g., In the Matter of Global Minerals & Metals Corp., Comm. Fut. L. Rep. (CCH) P28,655 (CFTC, Oct. 3, 2001). 17 C.F.R. § 10.101(a)(1)-(4). 17 C.F.R. § 10.101(a)(5). © 2015 THOMSON REUTERS Futures & Derivatives Law Report 54. 55. 56. 57. 58. 59. 60. 61. 62. 63. 64. 65. 66. 67. 68. 69. 70. 71. 72. 17 C.F.R. § 10.84. In the Matter of Ray, Comm. Fut. L. Rep. (CCH) P31, 914 (CFTC, Feb. 18, 2011); see also In the Matter of Mayer, Comm. Fut. L. Rep. (CCH) P28, 935 (CFTC, Feb. 28, 1998). In the Matter of Ray, supra (“in applying the weight or preponderance of the evidence standard … “); see also Reddy v. CFTC, 191 F.3d 109, 117 (2d Cir. 1999) (“However, our role in reviewing the Commission finding of preponderance is narrow.”). 17 C.F.R. § 10.102. Notice of appeal must be filed within 15 days after service of the initial decision or other order terminating the proceeding. Regulation 10.102 also specifies the procedures and requirements for filing crossappeals and briefs. In determining to permit cross-appeals by either party, the Commission noted that cross appeals have long been permitted under Federal Rule of Appellate Procedure 4(a)(3) “with no apparent abridgement of any party’s right to due process.” Rules of Practice, supra note 32, at 53,790. 17 C.F.R. § 10.105. 17 C.F.R. § 10.104(a). In the Matter of Grossfeld, Comm. Fut. L. Rep. (CCH) P26,921 (CFTC, Dec. 10, 1996). 17 C.F.R. § 10.103. Interviews with former Commission staff indicate that the Commission last held an oral argument in the late 1990s. 17 C.F.R. § 10.84(c)(2). CEA § 6(c)(11), 7 U.S.C. § 9(11) (2014). Timely appeal of an initial decision by an ALJ to the Commission is “mandatory as a prerequisite to seeking judicial review” of any final decision. 17 C.F.R. § 10.102(f). P.L. 93-463, Commodity Futures Trading Commission Act of 1974. P.L. 102-546, Futures Trading Practices Act of 1992, Sec. 221. 170 F.2d 220 (7th Cir. 1948) 201 F.2d 476 (7th Cir. 1953). 311 F.2d 52 (5th Cir. 1962). 452 F.2d 1154 (8th Cir. 1971). General Foods Corp. v. Brannan, 170 F.2d 220 (7th Cir. 1948). “The Seventh Circuit’s decision in this case did not sit well with the government, who viewed it as allowing price stabilizing and pegging of prices through futures trades in order to protect the price of a cash position.” Jerry W. Markham, Law Enforcement and the History of Financial Market Manipulation 102 (M.E. Sharpe, 2014). 311 F.2d at 59. See generally Jerry W. Markham, Manipulation of Commodity Futures Prices—The Unprosecutable Crime, 8 Yale Journal on Regulation 281, 352-358 (1991). At the time, commenters viewed the agency’s use of administrative en- © 2015 THOMSON REUTERS March 2015 73. 74. 75. 76. 77. 78. 79. 80. n Volume 35 n Issue 2 forcement process positively: “It is within the context of its own administrative enforcement and disciplinary proceedings, however, that the Commission is able to best articulate its jurisdictional and legislative philosophy and to exhibit to the professional community and investing public its ability to policy the commodity industry.” Michael S. Sackheim, Administrative Enforcement of the Federal Commodities Laws by the Commodity Futures Trading Commission, 12 Seton Hall L. Rev. 445, 447 (1982) (citations omitted). In the Matter of Hohenberg Bros., Comm. Fut. L. Rep. (CCH) P20,271 (CFTC, Feb. 18, 1977). The Commission concluded, however, that the evidence before it did not support a finding of attempted manipulation and dismissed the complaint. Id. In the Matter of Indiana Farm Bureau Coop. Ass’n, Comm. Fut. L. Rep. (CCH) P21,796 (CFTC, Dec. 17, 1982). Id. The Commission also dismissed the complaint. “This holding appeared to signal that the CFTC was adopting, and even extending, the Volkart decision that the CEA had sought to overturn by legislation.” Markham, The Unprosecutable Crime, supra note 72, at 189. The Commission also found the Division had not met its burden of proof and dismissed the complaint. In the Matter of Cox, Comm. Fut. L. Rep. (CCH) P23,786 (CFTC, July 15, 1987). Professor Markham termed the Cox case a “regulatory disaster,” Markham, History of Manipulation, supra note 70, at 191, and has argued that the CFTC, through its interpretations, “effectively nullified the manipulation prohibition.” Markham, The Unprosecutable Crime, supra note 72, at 285. See, e.g., CFTC v. Wilson, 13 Civ 7884 (S.D.N.Y. filed Nov. 6, 2013) (complaint alleging manipulation and attempted manipulation of threemonth interest rate swap futures contracts); CFTC v. Optiver, 08-CIV 6560 (S.D.N.Y. complaint filed July 24, 2008, final consent order filed April 19, 2012) (complaint alleging manipulation of the settlement price of crude oil, heating oil, and gasoline futures contracts); CFTC v. Parnon Energy, Arcadia Petroleum Ltd. And Arcadia Energy (Suisse) , 11 Civ. 3543 (S.D.N.Y. complaint filed May 24 2011; final consent order filed August 4, 2014) (complaint alleging manipulation and attempted manipulation of the price of crude oil futures contract spreads). U.S. General Accounting Office, Administrative Law Judges, Comparison of SEC and CFTC Programs, GAO/GGD-96-27 (Nov. 1995). During this period ALJs issued 46 initial decisions and the Commission ruled on 48 appeals of ALJ decisions. In 14 of these cases the Commission 13 March 2015 81. 82. 83. 84. 85. 86. 87. 14 n Volume 35 n Issue 2 reduced the sanction imposed by the ALJ, and in 4 of the appeals the Commission increased the sanction. Only one of the cases reviewed by GAO during this period involved manipulation. Id. In the Matter of Abrams, Comm. Fut. L. Rep. (CCH) P26,479 (CFTC, Jul. 31, 1995). Following the Commission’s dismissal of the complaint in Cox, one of the targets of the Commission’s investigation, George Frey, filed a request for attorney’s fees under the Equal Access to Justice Act. In 1991, the court dismissed Frey’s appeal of the Commission’s denial of attorney’s fees, finally concluding the case slightly more than 20 years after the conduct at issue occurred. Frey v. CFTC, 931 F.2d 1171 (7th Cir. 1991). Professor Markham notably has concluded that the Commission’s adjudicatory decisions in manipulation cases was a major reason for its difficulty in successfully prosecuting manipulation, “The small number of cases brought and the very small number of respondents who have been subject to significant sanctions, particularly in contested cases, suggest that manipulation is virtually an unprosecutable crime. This is due to the difficulty of meeting the standards of manipulation articulated by the CFTC.” Markham, The Unprosecutable Crime, supra note 72, at 356. Silverman v. CFTC, 549 F.2d 28 (7th Cir. 1977). Id. at 33 (internal citations omitted). Id. Gimbel v. CFTC, 872 F.2d 196 (2d Cir. 1989). Similarly, the Second Circuit has stated that “fundamental fairness requires a fair trial in a fair tribunal … with fair notice of the matters at issue and an opportunity to cross-examine witnesses.” Piccolo v. CFTC, 388 F.3d 387, 391 (2d Cir. 2004) (upholding Commission Order summarily affirming Exchange disciplinary action against trader for throwing first punch in brawl outside Exchange). Graham v. CFTC, 1988 U.S. App. LEXIS 22152 (9th Cir. 1988), quoting Chapman v. CFTC, 788 F.2d 408, 419 (7th Cir. 1986). See also McClelland v. Andrus, 606 F.2d 1278, 1285 (D.C. Cir. 1979) (“The extent of discovery that a party engaged in an administrative hearing is entitled to is primarily determined by the particular agency; both the Federal Rules of Civil Procedure and the Federal Rules of Criminal Procedure are inapplicable and the Administrative Procedure Act fails to provide expressly for discovery; further courts have consistently held that agencies Futures & Derivatives Law Report 88. 89. 90. 91. 92. 93. 94. 95. 96. 97. 98. 99. 100. 101. 102. 103. 104. 105. 106. need not observe all the rules and formalities applicable to courtroom proceedings.”). Lloyd Carr & Co. v. CFTC, 567 F.2d 1193 (2d Cir. 1977). Id. at 1196 (citation omitted). Id. at 1197. The Commission had argued that any evidence that would have been produced would not have affected the outcome. 7 U.S.C. § 9 (2008). Reddy v. CFTC, 191 F.3d 109, 114 (2d Cir. 1999). See also Haltmier v. CFTC, 554 F.2d 556, 560 (2d Cir. 1977) (“The ‘weight of evidence’ means ‘the preponderance’ or ‘greater weight of the evidence’” (citation omitted)). Great Western Foods, supra note 67, at 479-80; Reddy, supra; Haltmier, supra; Silverman, supra note 83. 5 U.S.C. §706(E). Airport Shuttle Service, Inc., v. Interstate Commerce Comm’n, 676 F.2d 836, 840 (D.C. Cir. 1982); see also , McHenry v. Bond, 668 F.2d 1185, 1190 (11th Cir. 1982) (“It is something more than a scintilla of evidence, but something less than the weight of the evidence.”). See note 93 and accompanying text, supra, quoting Chevron, U.S.A., Inc. v. Natural Res. Defense Council, 467 U.S. 837, 844 (1984). Monieson v. CFTC, 996 F.2d 852, 858 (7th Cir. 1993). Reddy v. CFTC, 191 F.3d 109, 124 (2d Cir. 1999), quoting Motor Vehicle Mfrs. Ass’n v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983) and Burlington Truck Lines v. United States, 371 U.S. 156, 168 (1962); see also DiPlacido v. CFTC, 364 Fed. Appx., 657 (2d Cir. 2009). . DiPlacido, supra, at 661. In Cargill v. Hardin, supra note 69, the defendant argued that the CEA’s “weight of the evidence” standard was “considerably more stringent” than the APA’s “substantial evidence” test. In response, the Eighth Circuit endorsed the standard of review set forth by the Seventh Circuit in General Foods Corp. v. Brannan.; see also Wilson v. CFTC, 322 F.3d 555 (8th Cir. 2003). Elliott v. CFTC, 202 F.3d 926 (7th Cir. 2000). Id., at 932. Id., at 940, Easterbrook, J. dissenting. Chau v. SEC, ___F. Supp.3d ___(S.D.N.Y.) 2014 WL 6984236. Id. Whitman v. U.S., 574 U.S. ___ (2014) (denial of petition for writ of certiorari, Scalia, J. dissenting) Id. © 2015 THOMSON REUTERS From: To: Subject: Date: Beth L. Soliere Bob Stump RE: HEPG Dinner Tuesday, October 04, 2016 10:45:01 AM ok   From: Bob Stump Sent: Tuesday, October 04, 2016 10:36 AM To: Beth L. Soliere Subject: Fwd: HEPG Dinner   Yes and also for mom  Sent from my iPhone Begin forwarded message: From: "Mahoney, Jo-Ann" Date: October 4, 2016 at 8:34:37 AM MST To: "Mahoney, Jo-Ann" Cc: "Gill, Susan" Subject: HEPG Dinner We look forward to your involvement in the Harvard Electricity Policy Group meeting to be held on Thursday-Friday, October 13-14, at the Watergate Hotel.    We plan to hold our reception and dinner on Thursday evening at Marcel’s.  Chef Robert Weidmaier will be preparing a special dinner for HEPG.  Kindly RSVP (regrets as well) to Susan Gill (susan_gill@hks.harvard.edu) by Thursday, October 6.   I look forward to seeing you next week.   Best, Jo-Ann       Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu     From: To: Cc: Subject: Date: Attachments: Mahoney, Jo-Ann Mahoney, Jo-Ann Gill, Susan HEPG Dinner Tuesday, October 04, 2016 8:34:44 AM HEPG_10_1314_DraftAgenda.docx We look forward to your involvement in the Harvard Electricity Policy Group meeting to be held on Thursday-Friday, October 13-14, at the Watergate Hotel.    We plan to hold our reception and dinner on Thursday evening at Marcel’s.  Chef Robert Weidmaier will be preparing a special dinner for HEPG.  Kindly RSVP (regrets as well) to Susan Gill (susan_gill@hks.harvard.edu) by Thursday, October 6.   I look forward to seeing you next week.   Best, Jo-Ann       Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu     HARVARD ELECTRICITY POLICY GROUP HARVARD ELECTRICITY POLICY GROUP EIGHTY-FOURTH PLENARY SESSION The Watergate Hotel Washington, DC THURSDAY AND FRIDAY, OCTOBER 13-14, 2016 DRAFT AGENDA Thursday, October 13 8:30 am Breakfast and Informal Discussion 9:00 am Session One. Transmission Rights and Revenues Redux: Follow the Money Financial Transmission Rights (FTR) arose in response to a problem in the design of electricity markets. Under open-access and non-discrimination principles, physical transmission rights could not be guaranteed to match transmission usage and could not provide a means of controlling operation of the system. Efficient market design requires a real-time market built as a bid-based, security-constrained economic dispatch with locational prices. The difference in location prices includes the effect of transmission congestion and marginal losses. Financial transmission rights provide the economic equivalent of the unavailable physical rights in hedging the difference in locational prices. The value of the financial rights incorporates the expected value of these price differences. The allocation of this value accrues to those who pay for the transmission system, either through allocation of financial transmission or through the revenues from forward auctions of financial transmission rights. The allocation of auction revenues can occur through the allocation of auction revenue rights (ARR). Over time, with changing grid conditions, any fixed allocation of rights could slowly disconnect from the total value of congestion and net loss payments. There is increasing concern with the results of these transmission related market elements. Is there a market design disconnect, between the allocation of payments for the grid and the value of congestion and losses? Are there problems of market manipulation of or with FTRs? How should the real-time, day-ahead and other forward market use of FTRs be kept consistent with the design principles? How should revenue surpluses or deficits for FTRs be treated? How can we evaluate the performance of FTRs and related markets? What alternative approaches are available for addressing the fundamental design issue in the search for hedges without physical transmission rights? Moderator: Abram Klein, Appian Way Energy Partners Joseph Bowring, Monitoring Analytics William Hogan, Harvard University Ryan Kurlinski, California Independent System Operator Andrew Stevens, DC Energy HEPG Draft Agenda, October 13-14, 2016 Thursday, October 13 (cont’d) 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Lunch 1:15 pm Session Two. Deciding Market Manipulation Cases: FERC Processes, Role of Judiciary, and Policy Coherence It has been a central theme of regulatory theory that regulators should have a central role in deciding matters within the scope of the agency jurisdiction. The theory is based on two fundamental premises: 1) the subject matter requires unique expertise that is possessed by a sector regulatory agency; and 2) the central role of the regulators in making sector related decisions makes policy coherence and consistency more likely. In regard to market manipulation cases, however, the Federal Power Act provides parties subject to allegations of market abuse to select whether to have their cases decided by the FERC, through Administrative Law processes, or to have a de novo proceeding in Federal District Court. In regard to choosing the latter, course, recent court decisions have suggested that FERC’s views are not entitled to the type of deference which might be accorded them through the ordinary appeals process for other regulatory decisions. What are the implications of these developments? Are we running the risk of having diverse courts making conflicting decisions? Why is the FERC Administrative Process not the preferable option, since it is more likely to produce a consistency? Should investigative and enforcement functions be completely walled off from adjudicatory proceedings at the agency, as they are in rate cases? If courts do conduct de novo proceedings, how much should they be obliged to follow FERC guidelines and precedents in determining what constitutes market manipulation? In terms of market stability and coherence in rules, what is the optimal process for deciding market manipulation cases? Moderator: Ashley Brown, Harvard Kennedy School Dan Berkovitz, WilmerHale John Estes, Skadden Arps William Scherman, Gibson Dunn Susan Court, SJC Energy Consultants 2:45 pm Coffee Break 3:00 pm Discussion 4:15 pm Adjourn 6:30 pm Reception and Dinner Marcel’s, 2401 Pennsylvania Avenue NW HEPG Draft Agenda, October 13-14, 2016 Friday, October 14 8:30 am Breakfast and Informal Discussion 9:00 am Session Three. Counting Carbon: Pricing Greenhouse Gas Pollution in RTO Markets A number of the ISO’s are considering new market-based mechanisms to reduce carbon emissions in their footprint of the electricity sector. Proposals range from centralized procurement programs for long-term renewable energy contracts to including a carbon price in day-ahead and real-time markets. For generators, a carbon adder could “level the playing field” and address carbon pollution more efficiently than the host of federal and state subsidies for clean generation and disparate carbon policies. Environmentalists may see an RTO carbon adder as a more achievable alternative to a national carbon tax or power sector cap-and-trade program. But these proposals present many questions. Does FERC have authority to approve carbon pricing in wholesale markets if presented with a proposal filed by an RTO? Or, could the Commission initiate its own rulemaking and direct RTOs to include a carbon price? What should the price be, and how should it be set? Would the market merely set a shadow price, or would the RTO collect the adder and reallocate the resulting proceeds? Would market carbon prices preempt, moot, or co-exist with state carbon and renewable energy policies? How would such a market impact or be impacted by the pricing of distributed solar generation? How would pre-existing greenhouse gas trading programs (AB32 and RGGI) react to RTO carbon pricing? What impact would such a market have on state regulation and policies? Moderator: Michael Wara, Stanford University Law School Kathleen Barron, Exelon Corporation Raj Barua, National Regulatory Research Institute Joel Eisen, University of Richmond Law School Rana Mukerji, New York Independent System Operator 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Adjourn From: To: Subject: Date: Attachments: Mahoney, Jo-Ann Mahoney, Jo-Ann Harvard Electricity Policy Group agenda Thursday, September 15, 2016 8:02:50 AM HEPG_10_1314_DraftAgenda.docx We look forward to your participation in the upcoming Harvard Electricity Policy Group to be held in Washington DC at the Watergate Hotel on Thursday-Friday, October 13-14.     Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu     HARVARD ELECTRICITY POLICY GROUP HARVARD ELECTRICITY POLICY GROUP EIGHTY-FOURTH PLENARY SESSION The Watergate Hotel Washington, DC THURSDAY AND FRIDAY, OCTOBER 13-14, 2016 DRAFT AGENDA Thursday, October 13 8:30 am Breakfast and Informal Discussion 9:00 am Session One. Transmission Rights and Revenues Redux: Follow the Money Financial Transmission Rights (FTR) arose in response to a problem in the design of electricity markets. Under open-access and non-discrimination principles, physical transmission rights could not be guaranteed to match transmission usage and could not provide a means of controlling operation of the system. Efficient market design requires a real-time market built as a bid-based, security-constrained economic dispatch with locational prices. The difference in location prices includes the effect of transmission congestion and marginal losses. Financial transmission rights provide the economic equivalent of the unavailable physical rights in hedging the difference in locational prices. The value of the financial rights incorporates the expected value of these price differences. The allocation of this value accrues to those who pay for the transmission system, either through allocation of financial transmission or through the revenues from forward auctions of financial transmission rights. The allocation of auction revenues can occur through the allocation of auction revenue rights (ARR). Over time, with changing grid conditions, any fixed allocation of rights could slowly disconnect from the total value of congestion and net loss payments. There is increasing concern with the results of these transmission related market elements. Is there a market design disconnect, between the allocation of payments for the grid and the value of congestion and losses? Are there problems of market manipulation of or with FTRs? How should the real-time, day-ahead and other forward market use of FTRs be kept consistent with the design principles? How should revenue surpluses or deficits for FTRs be treated? How can we evaluate the performance of FTRs and related markets? What alternative approaches are available for addressing the fundamental design issue in the search for hedges without physical transmission rights? Joseph Bowring, Monitoring Analytics William Hogan, Harvard University Ryan Kurlinski, California Independent System Operator Andrew Stevens, DC Energy Thursday, October 13 (cont’d) HEPG Draft Agenda, October 13-14, 2016 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Lunch 1:15 pm Session Two. Deciding Market Manipulation Cases: FERC Processes, Role of Judiciary, and Policy Coherence It has been a central theme of regulatory theory that regulators should have a central role in deciding matters within the scope of the agency jurisdiction. The theory is based on two fundamental premises: 1) the subject matter requires unique expertise that is possessed by a sector regulatory agency; and 2) the central role of the regulators in making sector related decisions makes policy coherence and consistency more likely. In regard to market manipulation cases, however, the Federal Power Act provides parties subject to allegations of market abuse to select whether to have their cases decided by the FERC, through Administrative Law processes, or to have a de novo proceeding in Federal District Court. In regard to choosing the latter, course, recent court decisions have suggested that FERC’s views are not entitled to the type of deference which might be accorded them through the ordinary appeals process for other regulatory decisions. What are the implications of these developments? Are we running the risk of having diverse courts making conflicting decisions? Why is the FERC Administrative Process not the preferable option, since it is more likely to produce a consistency? Should investigative and enforcement functions be completely walled off from adjudicatory proceedings at the agency, as they are in rate cases? If courts do conduct de novo proceedings, how much should they be obliged to follow FERC guidelines and precedents in determining what constitutes market manipulation? In terms of market stability and coherence in rules, what is the optimal process for deciding market manipulation cases? Dan Berkovitz, WilmerHale John Estes, Skadden Arps William Scherman, Gibson Dunn Susan Court, SJC Energy Consultants 2:45 pm Coffee Break 3:00 pm Discussion 4:15 pm Adjourn 6:30 pm Reception and Dinner Marcel’s, 2401 Pennsylvania Avenue NW HEPG Draft Agenda, October 13-14, 2016 Friday, October 14 8:30 am Breakfast and Informal Discussion 9:00 am Session Three. Counting Carbon: Pricing Greenhouse Gas Pollution in RTO Markets A number of the ISO’s are considering new market-based mechanisms to reduce carbon emissions in their footprint of the electricity sector. Proposals range from centralized procurement programs for long-term renewable energy contracts to including a carbon price in day-ahead and real-time markets. For generators, a carbon adder could “level the playing field” and address carbon pollution more efficiently than the host of federal and state subsidies for clean generation and disparate carbon policies. Environmentalists may see an RTO carbon adder as a more achievable alternative to a national carbon tax or power sector cap-and-trade program. But these proposals present many questions. Does FERC have authority to approve carbon pricing in wholesale markets if presented with a proposal filed by an RTO? Or, could the Commission initiate its own rulemaking and direct RTOs to include a carbon price? What should the price be, and how should it be set? Would the market merely set a shadow price, or would the RTO collect the adder and reallocate the resulting proceeds? Would market carbon prices preempt, moot, or co-exist with state carbon and renewable energy policies? How would such a market impact or be impacted by the pricing of distributed solar generation? How would pre-existing greenhouse gas trading programs (AB32 and RGGI) react to RTO carbon pricing? What impact would such a market have on state regulation and policies? Kathleen Barron, Exelon Corporation Raj Barua, National Regulatory Research Institute Joel Eisen, University of Richmond Law School Rana Mukerji, New York Independent System Operator 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Adjourn From: To: Subject: Date: Attachments: Beth L. Soliere Bob Stump Fwd: Invitation to Attend HEPG"s October 2016 Conference Friday, August 19, 2016 7:21:25 AM Commissioner Registration Form - Oct 2016.docx ATT00001.htm Begin forwarded message: From: "Bruner, Hannah" Date: August 19, 2016 at 5:04:30 AM MST To: Undisclosed recipients:; Subject: Invitation to Attend HEPG's October 2016 Conference Good morning,   On behalf of the Harvard Electricity Policy Group, it is my pleasure to announce that HEPG’s upcoming conference will be held on Thursday and Friday, October 13-14, 2016 at the Watergate Hotel in Washington, DC. We cordially invite you to attend.   Panel topics and descriptions will be distributed in the coming weeks.   Should you wish to attend, kindly complete and return the attached registration form. HEPG will be happy to arrange hotel lodging for the conference and reimburse travel expenses post conference.   For your planning purposes, HEPG’s December conference will be held on December 8 and 9 at the Four Seasons Troon North in Scottsdale, AZ.   Please do not hesitate to contact me if you have any questions or concerns. I look forward to your response and hope you have a wonderful weekend.   Best regards, Hannah Bruner Staff Assistant Harvard Electricity Policy Group 79 JFK Street, Box 84 Cambridge, MA 02138 (617) 496-6760     REGISTRATION FORM HEPG EIGHTY-FOURTH PLENARY SESSION THURSDAY AND FRIDAY, OCTOBER 13-14, 2016 THE WATERGATE HOTEL WASHINGTON, DC TO: HARVARD ELECTRICITY POLICY GROUP John F. Kennedy School of Government FROM: Name Title Affiliation Address Phone E-mail ______YES, I will be able to attend the HEPG Plenary Session. ______ NO, I will not be able to attend the meeting. ______ I would like to send my designee: Name Title Address Phone E-mail ___________________________ ___________________________ ___________________________ ___________________________ ___________________________ ___________________________ HOTEL INFORMATION The Watergate Hotel is located at 2650 Virginia Ave NW, Washington, DC 20037. . From: To: Subject: Date: Bob Stump Beth L. Soliere; Lauren A. Ferrigni Hepg Wednesday, June 01, 2016 8:06:56 PM Anyone know where it will be held? Location on campus not on the cal Sent from my iPhone From: Cc: Subject: Date: Bob Stump Bruner, Hannah; Beth L. Soliere Re: HEPG Agenda and Dinner Tuesday, May 24, 2016 12:03:27 PM Looking forward! I'll be by myself. Thanks. Bob Sent from my iPhone On May 24, 2016, at 11:22 AM, Mahoney, Jo-Ann wrote: Dear HEPG Participants,   We look forward to seeing you next week at the Harvard Electricity Policy Group meeting to be held at the Charles Hotel in Cambridge on Thursday-Friday, June 2-3.  Our agenda is attached.   We invite you to attend the conference reception and dinner on Thursday evening at Harvest Restaurant -- a Harvard Square institution for forty years.  The new chef Tyler Kinnett, named one of Boston Zagat’s 30 under 30,  will prepare a special meal for the group.  You are welcome to bring a guest who is travelling with you.  Please RSVP to Hannah_bruner@hks.harvard.edu by Friday, May 28.   Best regards, Jo-Ann     Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu     From: To: Cc: Subject: Date: Attachments: Mahoney, Jo-Ann Mahoney, Jo-Ann Bruner, Hannah HEPG Agenda and Dinner Tuesday, May 24, 2016 11:23:00 AM HEPG_6.16_Agenda lthd.docx Dear HEPG Participants,   We look forward to seeing you next week at the Harvard Electricity Policy Group meeting to be held at the Charles Hotel in Cambridge on Thursday-Friday, June 2-3.  Our agenda is attached.   We invite you to attend the conference reception and dinner on Thursday evening at Harvest Restaurant -- a Harvard Square institution for forty years.  The new chef Tyler Kinnett, named one of Boston Zagat’s 30 under 30,  will prepare a special meal for the group.  You are welcome to bring a guest who is travelling with you.  Please RSVP to Hannah_bruner@hks.harvard.edu by Friday, May 28.   Best regards, Jo-Ann     Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu     HARVARD ELECTRICITY POLICY GROUP HARVARD ELECTRICITY POLICY GROUP EIGHTY-THIRD PLENARY SESSION The Charles Hotel Cambridge, MA THURSDAY AND FRIDAY, JUNE 2-3, 2016 DRAFT AGENDA Thursday, June 2 8:30 am Breakfast and Informal Discussion 9:00 am Session One. Interregional Transmission Services and Operations: Beyond Order 1000 Increasing development of intermittent resources and reduced reserve margins of traditional resources require leveraging diversity in regional supply and demand. Western utilities are moving towards an energy imbalance market to meet these emerging portfolio challenges. Some utilities and RTOs have developed voluntary coordination and congestion management agreements with varying governance structures and sophistication. These agreements can result in a patchwork of ad hoc bilateral agreements without full integration of the markets. While FERC directed interregional planning reforms with efforts in its Order 1000 initiative, it did not address operations or transmission services reform across transmission provider seams. The Commission’s Order 890 Rulemaking (2007) and the Inquiry into Transmission Loading Relief Reliability Standard and Curtailment Priorities (2010) have not produced significant advances in operational coordination. What opportunities are there to ensure maximum utilization of infrastructure across each interconnection and leverage interregional diversity? What can be done to move toward more efficient dispatch and congestion management across each interconnection? What operational opportunities can be leveraged with the eventual implementation of the Parallel Flow Visualization effort? With the development of Order 1000 interregional planning processes and cost allocations, should the traditional “through-and-out” transmission rate structures with rate-pancaking across systems be reevaluated? Should contract path or point-to-point based transmission service be supplemented or replaced with compensation mechanisms based on loop flow impacts to neighboring systems? Under what organizational and process umbrella (i.e. FERC, NERC, NAESB, or Voluntary Regional JOAs) can opportunities for advancement in interregional operations be made most effect? Moderator: Mark Christie, Virginia State Corporation Commission Stu Bresler, PJM Interconnection Keith Casey, California ISO Jennifer Curran, Midcontinent ISO Todd Lucas, Southern Company HEPG Draft Agenda, June 2-3, 2016 Thursday, June 2 (cont’d) 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Lunch 1:15 pm Session Two. Retail Rates: What Are We Missing by Perpetuating Tariffs without Meaningful Price Signals? Retail electric rates in the U.S., with a few exceptions, remain largely devoid of meaningful price signals. Rates tend to be based on average costs, insensitive to the real time dynamics of supply and demand, deprived of transparent demand cost price signals for at least some customer classes, and completely unreflective of the realities of fixed and variable costs. In the absence of meaningful prices, we have launched into debates about “value” of assets, net metering, customer desires, social externalities, and a host of other highly subjective, often non-economic considerations. While there is nothing new about those debates, there is the very basic question of why in the age of smart technology, sophisticated wholesale price signals, corporate and/or functional unbundling, and consciousness of the need for greater efficiency in energy use, we perpetuate a pricing regime devoid of meaningful signals. What are we missing by not moving to more meaningful pricing? What products, technologies, services and/or market participants, for example, are kept out of the market? To what degree is retail competition impeded by the absence of meaningful retail price signals. Indeed, would greater retail competition lead to greater efficiency through a broader array of offerings or perhaps impede it because, as some have argued, retail merchants will sell hedged products that could dilute improved price signals? Moderator: Ellen Roy Herzfelder, Delta Properties Paul Centolella, Paul Centolella & Associates John Howat, National Consumer Law Center John Kelly, Green Business Certification Inc. Jim Steffes, Direct Energy 2:45 pm Coffee Break 3:00 pm Discussion 4:15 pm Adjourn 6:00 pm Reception and Dinner HEPG Draft Agenda, June 2-3, 2016 Friday, June 3 8:30 am Breakfast and Informal Discussion 9:00 am Session Three. Clean Energy Revolution or Evolution: The Cost of Renewables The cost of renewable energy has been declining, rapidly. The improvements have been enormous. The controversy remains not over whether there has been a substantial cost improvement but whether the cost reduction is enough to turn the corner on the economics of meeting the challenges of climate change. The debate has major implications for a policy choice between wide scale subsidies for deployment of existing technologies versus substantial increased expenditures on R&D to develop breakthroughs that can be deployed in the future. The views range from “[o]ne popularized myth about [Renewable Electricity] is that it is simply too expensive,” (NREL) to “[t]he cost of renewables has been falling. But not fast enough.” (Global Apollo Programme). Differences in the estimates of the cost of renewables are at the core of the analysis of options under of the Clean Power Program. The Energy Information Administration issued a recent report defending its higher estimates of the cost of renewables against a continuing series of critiques. What are the debates and sources of differences in the estimates of the cost of renewables? How do regional variations affect the picture? What are the trends in costs? What does this imply for the appropriate subsidy policies for deployment and learning by doing? How important is it to expand on the R&D budget and focus on major breakthroughs rather than incremental improvements? Is the revolution already here, or as Bill Gates says “we need an energy miracle.” Moderator: Julie Simon, Federal Energy Regulatory Commission Daniel Gabaldon, Enovation Partners Rob Gramlich, American Wind Energy Association Howard Gruenspecht, Energy Information Administration Joshua Rhodes, University of Texas in Austin 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Adjourn From: To: Subject: Date: Bob Stump Beth L. Soliere HEPG Monday, May 23, 2016 11:47:12 PM Calendar has it adjourning on the 2nd -- assume you meant the 3rd? I'm going to look for Hannah's email to see. -Bob Stump Chair, Phoenix Opera 3120 West Carefree Highway, Suite 1-106 Phoenix, AZ 85086   Commissioner, Arizona Corporation Commission 1200 W. Washington Phoenix, AZ  85007 602-542-3935 From: To: Subject: Date: Bob Stump Beth L. Soliere HEPG Wednesday, May 18, 2016 3:29:49 PM Do you have the agenda? -Bob Stump Chair, Phoenix Opera 3120 West Carefree Highway, Suite 1-106 Phoenix, AZ 85086   Commissioner, Arizona Corporation Commission 1200 W. Washington Phoenix, AZ  85007 602-542-3935 From: To: Subject: Date: Attachments: Bruner, Hannah Beth L. Soliere FW: The Harvard Faculty Club Reservation Confirmation Tuesday, May 17, 2016 10:13:05 AM HEPG_6.16_Agenda lthd.docx Good afternoon, Beth, Please find the hotel reservation confirmation below. I am also attaching the updated agenda, which lists the speakers for each panel. Have a nice day! Best wishes, Hannah   From: hfc@harvard.edu [mailto:hfc@harvard.edu] Sent: Monday, May 09, 2016 4:27 PM To: Bruner, Hannah Subject: The Harvard Faculty Club Reservation Confirmation HARVARD UNIVERSITY THE HARVARD FACULTY CLUB RESERVATION CONFIRMATION Reservation # 19174 Guest Details Name: Address: Robert Stump 1200 W. Washington St. Phoenix, AZ 85007 Reservation Details Arrival Date: Departure Date: Number of Nights:  # of Guests: June 1, 2016 June 3, 2016 2 1 From Wednesday, June 1, 2016 to Friday, 3, 2016 Daily Rate: 2 night(s) at $259.00 - Standard Rate May 29 - June 30 Total Charges Due: $518.00 CHECK-IN/OUT INFORMATION CHECK-IN: Not before 3pm.          CHECK-OUT:10am The Front Desk is staffed 24 hours per day but the entry to the Club is locked in the evenings. Please ring the doorbell located to the left of the door. Alternatively, you may enter your reservation number on the keypad to the left of the door, or you may use your room key-card to gain entry. Once inside, please proceed to the Front Desk. IMPORTANT NOTICE CANCELLATIONS: Written notification is required via either email or fax. Cancellations 3 days or more in advance of the check-in date = no penalty. Cancellations/early departures fewer than 3 days in advance = a penalty of 50% of the entire reservation. PARKING: $20 per day RATES ARE SUBJECT TO CHANGE WITHOUT NOTICE. GUEST AMENITIES Complimentary continental breakfast is served most weekday mornings from 7:00 until 10:00. Each bedroom is equipped with a TV, clock radio, telephone, hair dryer and high speed wired and wireless internet access. A shared kitchenette offers ice, coffee, tea, and an iron & ironing board. Speak with the Front Desk attendant about our restaurants and bar. WE LOOK FORWARD TO SEEING YOU AND THANK YOU FOR YOUR PATRONAGE 20 QUINCY STREET CAMBRIDGE, MASSACHUSETTS 02138 (617) 495-5758 FAX (617) 496-8754 hfc@harvard.edu www.hfc.harvard.edu HARVARD ELECTRICITY POLICY GROUP HARVARD ELECTRICITY POLICY GROUP EIGHTY-THIRD PLENARY SESSION The Charles Hotel Cambridge, MA THURSDAY AND FRIDAY, JUNE 2-3, 2016 DRAFT AGENDA Thursday, June 2 8:30 am Breakfast and Informal Discussion 9:00 am Session One. Interregional Transmission Services and Operations: Beyond Order 1000 Increasing development of intermittent resources and reduced reserve margins of traditional resources require leveraging diversity in regional supply and demand. Western utilities are moving towards an energy imbalance market to meet these emerging portfolio challenges. Some utilities and RTOs have developed voluntary coordination and congestion management agreements with varying governance structures and sophistication. These agreements can result in a patchwork of ad hoc bilateral agreements without full integration of the markets. While FERC directed interregional planning reforms with efforts in its Order 1000 initiative, it did not address operations or transmission services reform across transmission provider seams. The Commission’s Order 890 Rulemaking (2007) and the Inquiry into Transmission Loading Relief Reliability Standard and Curtailment Priorities (2010) have not produced significant advances in operational coordination. What opportunities are there to ensure maximum utilization of infrastructure across each interconnection and leverage interregional diversity? What can be done to move toward more efficient dispatch and congestion management across each interconnection? What operational opportunities can be leveraged with the eventual implementation of the Parallel Flow Visualization effort? With the development of Order 1000 interregional planning processes and cost allocations, should the traditional “through-and-out” transmission rate structures with rate-pancaking across systems be reevaluated? Should contract path or point-to-point based transmission service be supplemented or replaced with compensation mechanisms based on loop flow impacts to neighboring systems? Under what organizational and process umbrella (i.e. FERC, NERC, NAESB, or Voluntary Regional JOAs) can opportunities for advancement in interregional operations be made most effect? Stu Bresler, PJM Interconnection Keith Casey, California ISO Jennifer Curran, Midcontinent ISO John Trawick, Southern Company HEPG Draft Agenda, June 2-3, 2016 Thursday, June 2 (cont’d) 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Lunch 1:15 pm Session Two. Retail Rates: What Are We Missing by Perpetuating Tariffs without Meaningful Price Signals? Retail electric rates in the U.S., with a few exceptions, remain largely devoid of meaningful price signals. Rates tend to be based on average costs, insensitive to the real time dynamics of supply and demand, deprived of transparent demand cost price signals for at least some customer classes, and completely unreflective of the realities of fixed and variable costs. In the absence of meaningful prices, we have launched into debates about “value” of assets, net metering, customer desires, social externalities, and a host of other highly subjective, often non-economic considerations. While there is nothing new about those debates, there is the very basic question of why in the age of smart technology, sophisticated wholesale price signals, corporate and/or functional unbundling, and consciousness of the need for greater efficiency in energy use, we perpetuate a pricing regime devoid of meaningful signals. What are we missing by not moving to more meaningful pricing? What products, technologies, services and/or market participants, for example, are kept out of the market? To what degree is retail competition impeded by the absence of meaningful retail price signals. Indeed, would greater retail competition lead to greater efficiency through a broader array of offerings or perhaps impede it because, as some have argued, retail merchants will sell hedged products that could dilute improved price signals? Paul Centolella, Paul Centolella & Associates John Howat, National Consumer Law Center John Kelly, Green Business Certification Inc. Jim Steffes, Direct Energy 2:45 pm Coffee Break 3:00 pm Discussion 4:15 pm Adjourn 6:00 pm Reception and Dinner HEPG Draft Agenda, June 2-3, 2016 Friday, June 3 8:30 am Breakfast and Informal Discussion 9:00 am Session Three. Clean Energy Revolution or Evolution: The Cost of Renewables The cost of renewable energy has been declining, rapidly. The improvements have been enormous. The controversy remains not over whether there has been a substantial cost improvement but whether the cost reduction is enough to turn the corner on the economics of meeting the challenges of climate change. The debate has major implications for a policy choice between wide scale subsidies for deployment of existing technologies versus substantial increased expenditures on R&D to develop breakthroughs that can be deployed in the future. The views range from “[o]ne popularized myth about [Renewable Electricity] is that it is simply too expensive,” (NREL) to “[t]he cost of renewables has been falling. But not fast enough.” (Global Apollo Programme). Differences in the estimates of the cost of renewables are at the core of the analysis of options under of the Clean Power Program. The Energy Information Administration issued a recent report defending its higher estimates of the cost of renewables against a continuing series of critiques. What are the debates and sources of differences in the estimates of the cost of renewables? How do regional variations affect the picture? What are the trends in costs? What does this imply for the appropriate subsidy policies for deployment and learning by doing? How important is it to expand on the R&D budget and focus on major breakthroughs rather than incremental improvements? Is the revolution already here, or as Bill Gates says “we need an energy miracle.” Daniel Gabaldon, Enovation Partners Rob Gramlich, American Wind Energy Association Howard Gruenspecht, Energy Information Administration Joshua Rhodes, University of Texas in Austin 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Adjourn From: To: Subject: Date: Attachments: Bob Stump Beth L. Soliere Fwd: Invitation to Attend HEPG"s June Conference Monday, May 02, 2016 8:10:46 AM Commissioner Registration Form - June 2016.docx ATT00001.htm Sent from my iPhone Begin forwarded message: From: "Bruner, Hannah" Date: April 29, 2016 at 12:55:04 PM MST To: Bob Stump Cc: "Beth L. Soliere" Subject: Invitation to Attend HEPG's June Conference Dear Commissioner Stump,   The Harvard Electricity Policy Group’s next session will take place in Cambridge, MA on Thursday and Friday, June 2 and 3 at the Charles Hotel. If your schedule permits, we would be delighted for you to join us.   Our topics for this session are “Interregional Transmission Services and Operations: Beyond Order 1000,” “Clean Energy Revolution or Evolution: The Cost of Renewables,” and a third topic. Please see the full panel descriptions below.   Kindly complete and return the attached registration form at your earliest convenience.   Please do not hesitate to contact me if you have any questions or concerns. I look forward to your response and hope you will join us in Cambridge.   Thank you for your time and consideration, and have a lovely weekend.   Warm regards, Hannah Bruner Staff Assistant Harvard Electricity Policy Group 79 JFK Street, Box 84 Cambridge, MA 02138 (617) 496-6760       Interregional Transmission Services and Operations: Beyond Order 1000 Increasing development of intermittent resources and reduced reserve margins of traditional resources require leveraging diversity in regional supply and demand.  Western utilities are moving towards an energy imbalance market to meet these emerging portfolio challenges.  Some utilities and RTOs have developed voluntary coordination and congestion management agreements with varying governance structures and sophistication.  These agreements can result in a patchwork of ad hoc bilateral agreements without full integration of the markets. While FERC directed interregional planning reforms with efforts in its Order 1000 initiative, it did not address operations or transmission services reform across transmission provider seams.  The Commission’s Order 890 Rulemaking (2007) and the Inquiry into Transmission Loading Relief Reliability Standard and Curtailment Priorities (2010) have not produced significant advances in operational coordination.  What opportunities are there to ensure maximum utilization of infrastructure across each interconnection and leverage interregional diversity? What can be done to move toward more efficient dispatch and congestion management across each interconnection? What operational opportunities can be leveraged with the eventual implementation of the Parallel Flow Visualization effort? With the development of Order 1000 interregional planning processes and cost allocations, should the traditional “through-and-out” transmission rate structures with rate-pancaking across systems be reevaluated? Should contract path or point-to-point based transmission service be supplemented or replaced with compensation mechanisms based on loop flow impacts to neighboring systems? Under what organizational and process umbrella (i.e. FERC, NERC, NAESB, or Voluntary Regional JOAs) can opportunities for advancement in interregional operations be made most effect?   Clean Energy Revolution or Evolution:  The Cost of Renewables The cost of renewable energy has been declining, rapidly.  The improvements have been enormous.  The controversy remains not over whether there has been a substantial cost improvement but whether the cost reduction is enough to turn the corner on the economics of meeting the challenges of climate change.  The debate has major implications for a policy choice between wide scale subsidies for deployment of existing technologies versus substantial increased expenditures on R&D to develop breakthroughs that can be deployed in the future.  The views range from “[o]ne popularized myth about [Renewable Electricity] is that it is simply too expensive,” (NREL) to “[t]he cost of renewables has been falling. But not fast enough.” (Global Apollo Programme).  Differences in the estimates of the cost of renewables are at the core of the analysis of options under of the Clean Power Program.  The Energy Information Administration issued a recent report defending its higher estimates of the cost of renewables against a continuing series of critiques.  What are the debates and sources of differences in the estimates of the cost of renewables?  How do regional variations affect the picture?  What are the trends in costs?  What does this imply for the appropriate subsidy policies for deployment and learning by doing?  How important is it to expand on the R&D budget and focus on major breakthroughs rather than incremental improvements?  Is the revolution already here, or as Bill Gates says “we need an energy miracle.”     REGISTRATION FORM HEPG EIGHTY-THIRD PLENARY SESSION THURSDAY AND FRIDAY, JUNE 2-3, 2016 THE CHARLES HOTEL CAMBRIDGE, MA TO: HARVARD ELECTRICITY POLICY GROUP John F. Kennedy School of Government FROM: Name Title Affiliation Address Phone E-mail __________________________________ ______YES, I will be able to attend the HEPG Plenary Session. ______ NO, I will not be able to attend the meeting. ______ I would like to send my designee: Name Title Address Phone E-mail ___________________________ ___________________________ ___________________________ ___________________________ ___________________________ ___________________________ HOTEL INFORMATION We have reserved a block of rooms at the Harvard Faculty Club for the evenings of Wednesday, March 9 and Thursday, March 10. Please arrange your reservation through Hannah Bruner in the Harvard Electricity Policy Group (Hannah_Bruner@hks.harvard.edu) at your earliest convenience. The Harvard Faculty Club is located at 20 Quincy Street, Cambridge, MA 02138. To register for the session, please e-mail this reply form to: Hannah Bruner, HEPG Staff Assistant Hannah_Bruner@hks.harvard.edu From: To: Subject: Date: Beth L. Soliere Bob Stump FW: E-Ticket Confirmation-QFPVCW 09MAR Monday, April 25, 2016 10:59:59 AM Should I see if EEI can pick up part of the plane ticket as well since they offered to pay expenses?   From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Monday, April 25, 2016 10:59 AM To: Beth L. Soliere Subject: RE: E-Ticket Confirmation-QFPVCW 09MAR Hi, Beth, I hope you had a nice weekend. I apologize for my delay in response. I spoke with Jo-Ann, and she says HEPG can cover $500 of the plane ticket. Is that okay? Our June meeting will be in Cambridge on June 2 and 3. Best wishes, Hannah   From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Monday, April 25, 2016 12:28 PM To: Bruner, Hannah Subject: RE: E-Ticket Confirmation-QFPVCW 09MAR Hi Hannah,   Just checking to see if you saw this email I sent last week. Also I am wondering if you can tell me the dates for HEPG in June?   Thanks!   Beth   From: Beth L. Soliere Sent: Wednesday, April 20, 2016 10:15 AM To: 'Bruner, Hannah' Subject: FW: E-Ticket Confirmation-QFPVCW 09MAR Hi Hannah,   I am preparing Commissioner Stump’s reimbursement for the last HEPG.  The flight was very expensive, would you like us to pay a portion of this?   Thanks,   Beth   From: Bob Stump [mailto:repbobstump@gmail.com] Sent: Friday, March 04, 2016 9:42 PM To: Beth L. Soliere Subject: Fwd: E-Ticket Confirmation-QFPVCW 09MAR Let's offer to pay some of this for Harvard. Way too high. ---------- Forwarded message ---------From: American Airlines@aa.com Date: Friday, March 4, 2016 Subject: E-Ticket Confirmation-QFPVCW 09MAR To: "STUMPCAMPAIGN@GMAIL.COM" Ticket Issued: Mar 4, 2016 Christopher R Stump, Thank you for choosing American Airlines / American Eagle, a member of the oneworld® Alliance.  Below are your itinerary and receipt for the ticket(s) purchased.  Please print and retain this document for use throughout your trip. You may check in and obtain your boarding pass for U.S. domestic electronic tickets within 24 hours of your flight time online at AA.com by using  www.aa.com/checkin or at a Self-Service Check-In machine at the airport.  Check-in options may be found at  www.aa.com/options.   For information regarding American Airlines checked baggage policies, please visit www.aa.com/baggageinfo. To receive updated flight status notifications, please visit www.aa.com/notifications. 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Record Locator QFPVCW Carrier American Christopher Stump American Airlines Flight # Departing 680 PHOENIX WED 09MAR 1:55 PM Seat 5B Economy 4693 WASHINGTON REAGAN FRI 18MAR 4:59 PM Arriving WASHINGTON REAGAN Fare Code L 8:02 PM FF#: 2J6XY42 PLT Food For Purchase ATLANTA V 7:03 PM OPERATED BY REPUBLIC AIRLINES AS AMERICAN EAGLE Christopher Stump American Christopher Stump Passenger Seat 4C Economy FF#: 2J6XY42 PLT   ATLANTA FRI 18MAR 8:30 PM PHOENIX 611 Economy FF#: 2J6XY42 PLT Seat 4C Ticket # Fare-USD   Christopher Stump 0012323551197 V 9:44 PM Food For Purchase Taxes and CarrierTicket Total Imposed Fees 984.18 110.52 1094.70 Baggage Information Baggage charges for your itinerary will be governed by American Airlines BAG ALLOWANCE -PHXDCA-No free checked bags/ American Airlines BAG ALLOWANCE -DCAPHX-No free checked bags/ American Airlines 1STCHECKED BAG FEEPHXDCA-USD0.00/ American Airlines /UP TO 50 LB/23 KG AND UP TO 62 LINEAR IN/158 LINEAR CM 1STCHECKED BAG FEE-DCAPHX-USD0.00/ American Airlines /UP TO 50 LB/23 KG AND UP TO 62 LINEAR IN/158 LINEAR CM 2NDCHECKED BAG FEE-PHXDCA-USD0.00/ American Airlines /UP TO 50 LB/23 KG AND UP TO 62 LINEAR IN/158 LINEAR CM 2NDCHECKED BAG FEE-DCAPHX-USD0.00/ American Airlines /UP TO 50 LB/23 KG AND UP TO 62 LINEAR IN/158 LINEAR CM ADDITIONAL ALLOWANCES AND/OR DISCOUNTS MAY APPLY You have purchased a NON-REFUNDABLE fare. 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NOTICE: This email and any information, files or attachments are for the exclusive and confidential use of the intended recipient(s).  This message contains confidential and proprietary information of American Airlines (such as customer and business data) that may not be read, searched, distributed or otherwise used by anyone other than the intended recipient.  If you are not an intended recipient, please do not read, distribute, or take action in reliance upon this message.   If you suspect you have received this email in error, please notify the sender and promptly delete this message and its attachments from your computer. Conditions of Carriage Notification Special Assistance Flight Check-in Flight Status NRID: 2746566213330422333868200 -Bob Stump Chair, Phoenix Opera 3120 West Carefree Highway, Suite 1-106 Phoenix, AZ 85086 Commissioner, Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 602-542-3935 From: To: Subject: Date: Beth L. Soliere Bob Stump RE: HEPG Monday, April 25, 2016 10:55:13 AM What time will you be here? -----Original Message----From: Bob Stump Sent: Monday, April 25, 2016 9:30 AM To: Beth L. Soliere Subject: Re: HEPG Found it - June 2-3 Sent from my iPhone > On Apr 25, 2016, at 9:14 AM, Beth L. Soliere wrote: > > I'm trying to get an exact date. It's not listed on their website. I am going to email Hannah again today about that as well as the flight reimbursement. > > -----Original Message----> From: Bob Stump > Sent: Sunday, April 24, 2016 6:20 PM > To: Beth L. Soliere > Subject: HEPG > > Could you put that on my cal - it's sometime in June. Thx > > Sent from my iPhone From: To: Subject: Date: Attachments: Bob Stump Beth L. Soliere Fwd: HEPG Agenda and Dinner RSVP Wednesday, March 02, 2016 1:00:24 PM HEPG_3-16_DraftAgenda lthd.docx ATT00001.htm Sent from my iPhone Begin forwarded message: From: "Mahoney, Jo-Ann" Date: March 2, 2016 at 11:26:17 AM MST To: "Mahoney, Jo-Ann" Cc: "Bruner, Hannah" Subject: HEPG Agenda and Dinner RSVP We look forward to your participation in the Harvard Electricity Policy Group plenary session to be held at the Four Seasons Georgetown on March 10-11, 2016  (Agenda attached).   We invite you to attend our conference reception and dinner on Thursday evening, March 10.  The reception will take place at 6:00 pm at ENO wine bar in Georgetown followed by a special dinner created by Chef Michael Mina of Bourbon Steak.  This dinner will be held in the Seasons space at the hotel, and the reception is adjacent to the hotel.  You are welcome to bring a guest who is travelling with you. Kindly RSVP to Hannah Bruner by Friday, March 4:  Hannah_bruner@hks.harvard.edu   Best regards, Jo-Ann         Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu     HARVARD ELECTRICITY POLICY GROUP HARVARD ELECTRICITY POLICY GROUP EIGHTY-SECOND PLENARY SESSION The Four Seasons Washington, DC THURSDAY AND FRIDAY, MARCH 10-11, 2016 DRAFT AGENDA Thursday, March 10 8:30 am Breakfast and Informal Discussion 9:00 am Session One. Regulatory-Market Arbitrage: From Rate Base to Market and Back Again At the time of electricity market restructuring, many vertically integrated utilities sold their generating assets, or took them out of rate base and made them market-based assets. Many of these companies recovered “stranded asset” value, namely the difference between the remaining book value and the estimated market value of those facilities. The actual market value of the plants has fluctuated over time. Recently, particularly in regard to coal and nuclear facilities, the value of those plants has declined. Some utilities seek either a return of those plants to rate base or a new long-term contract that is an economic equivalent. The benefits of such arrangements are cited to include providing a consumer hedge against price volatility, added levels of reliability, and resource diversity that has long term value. What do such movements of assets say about the viability of competitive markets? If the consumers benefits of price hedging, resource diversity, and so on are there what arrangements provide the most efficient way to obtain them? Should consumers get some credit for having already paid (in full or in part) either when they were in rate base, or through stranded asset payments? What effect, if any, will such arrangements have on retail choice? At the federal regulatory level, what impacts do such proposed contracts have on electricity energy and capacity markets? What impact should such arrangements have market pricing authority? Moderator: Joseph Kelliher, NextEra Energy Barbara Alexander, Consumer Affairs Consultant Michael Dowling, FirstEnergy Corporation William Mohl, Entergy John Shelk, Electric Power Supply Association HEPG Draft Agenda, March 10-11, 2016 Thursday, March 10 (cont’d) 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Lunch 1:15 pm Session Two. Stakeholder Processes: “The Worst Form of Government, except for All the Others” Organized markets under Regional Transmission Owners need a stakeholder process to consider and analyze all manner of reforms and improvements in market rules and operations. Although not strictly a democracy, the analogy is apt about the promise and complications of any governance mechanism that respects and draws on different or competing perspectives. The different experiences across RTOs allow for an examination of the functioning of stakeholder processes. How well are stakeholder processes working? What are the major examples of success and what are the examples of challenges? How have stakeholder processes evolved over time? Have stakeholder processes created so many committees and meetings that only the best funded of stakeholders can really influence outcomes as opposed to those with the best ideas? Have the stakeholder groups become more inclusive or exclusive? Who is the stakeholder that represents efficient markets? Are the RTOs susceptible to lobbying pressures and capture by certain interested stakeholders? What are the lessons and major opportunities for improvements? Are the processes too cumbersome, or just cumbersome enough? Moderator: Philip Moeller, Edison Electric Institute Dave Anders, PJM Interconnection Bruce Bleiweis, DC Energy Jeff Nelson, Southern California Edison Elizabeth Wilson, University of Minnesota 2:45 pm Coffee Break 3:00 pm Discussion 4:15 pm Adjourn 6:00 pm Reception and Dinner HEPG Draft Agenda, March 10-11, 2016 Friday, March 11 8:30 am Breakfast and Informal Discussion 9:00 am Session Three. Uneconomic Dispatch?: Frontier Challenges in Dispatch and Pricing The changing structure of dispatch to incorporate the challenges of electricity markets presents opportunities for reforms in operations and pricing. New work from the European experience points to dispatch problems from the constant cycling of flexible fossil units. Wear and tear, a cost that is familiar for regulation assets, now becomes a possibly material problem for load-following units working on a different time scale. The impact can include accelerated requirements for maintenance. Yet dispatch models do not account for these effects, and the prices don’t capture the costs. Other advances in dispatch and pricing give attention to the block loading and startup inflexibilities that require extended locational marginal pricing. What are the pressures that are driving dispatch models? How is the technology of renewables or conventional fossil plants changing to avoid or adapt to these new challenges? What generator, dispatch, pricing concerns might be pushing the envelope? Moderator: Tony Clark, Federal Energy Regulatory Commission Matthew Barmack, Calpine Corporation Debra Lew, General Electric Todd Ramey, Midcontinent ISO Sonja Wogrin, Universidad Pontificia Comillas 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Adjourn From: To: Subject: Date: Bruner, Hannah Beth L. Soliere RE: HEPG"s March Conference Wednesday, March 02, 2016 8:12:20 AM Hello, Beth, Certainly. We already have him registered and his room reserved. Best, Hannah   From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Tuesday, March 01, 2016 4:55 PM To: Andrea Gaston Cc: Bruner, Hannah Subject: FW: HEPG's March Conference   Hi Hannah,   Chairman Little’s assistant Andrea is new and we need to make sure that he is registered for this month’s HEPG and hopefully get him a room as well. Can you help her out?   Thanks!   Beth   From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Tuesday, February 16, 2016 12:51 PM To: Beth L. Soliere Subject: HEPG's March Conference   Dear Beth, Please find attached the most recent agenda and registration form for HEPG’s March meeting, which will be help on March 10-11 in Washington, DC at the Four Seasons Georgetown. We cordially invite Commissioner Stump to attend. I apologize for reaching out so late. We’ve had several set-backs in planning due to circumstances in DC. Thank you, and have a nice day. Best regards,   Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School Belfer 313 (617) 496-6760 Hannah_Bruner@hks.harvard.edu From: To: Subject: Date: Beth L. Soliere Bob Stump RE: Hepg Friday, February 19, 2016 1:11:55 PM I couldn't find it online. Just asked Hannah. -----Original Message----From: Bob Stump Sent: Friday, February 19, 2016 12:40 PM To: Beth L. Soliere Subject: Hepg Do we know when the one in Cambridge is? I'm thinking June? Sent from my iPhone From: To: Subject: Date: Bob Stump Beth L. Soliere Re: HEPG"s March Conference Tuesday, February 16, 2016 1:50:44 PM Yes. Thanks  Sent from my iPhone On Feb 16, 2016, at 3:20 PM, Beth L. Soliere wrote: Yes?   From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Tuesday, February 16, 2016 12:51 PM To: Beth L. Soliere Subject: HEPG's March Conference   Dear Beth, Please find attached the most recent agenda and registration form for HEPG’s March meeting, which will be help on March 10-11 in Washington, DC at the Four Seasons Georgetown. We cordially invite Commissioner Stump to attend. I apologize for reaching out so late. We’ve had several set-backs in planning due to circumstances in DC. Thank you, and have a nice day. Best regards,   Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School Belfer 313 (617) 496-6760 Hannah_Bruner@hks.harvard.edu   From: To: Subject: Date: Attachments: Bruner, Hannah Beth L. Soliere HEPG"s March Conference Tuesday, February 16, 2016 12:51:23 PM HEPG_3-16_DraftAgenda lthd.docx Commissioner Registration Form - March 2016.docx Dear Beth, Please find attached the most recent agenda and registration form for HEPG’s March meeting, which will be help on March 10-11 in Washington, DC at the Four Seasons Georgetown. We cordially invite Commissioner Stump to attend. I apologize for reaching out so late. We’ve had several set-backs in planning due to circumstances in DC. Thank you, and have a nice day. Best regards,   Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School Belfer 313 (617) 496-6760 Hannah_Bruner@hks.harvard.edu   HARVARD ELECTRICITY POLICY GROUP HARVARD ELECTRICITY POLICY GROUP EIGHTY-SECOND PLENARY SESSION The Four Seasons Washington, DC THURSDAY AND FRIDAY, MARCH 10-11, 2016 DRAFT AGENDA Thursday, March 10 8:30 am Breakfast and Informal Discussion 9:00 am Session One. Regulatory-Market Arbitrage: From Rate Base to Market and Back Again At the time of electricity market restructuring, many vertically integrated utilities sold their generating assets, or took them out of rate base and made them market-based assets. Many of these companies recovered “stranded asset” value, namely the difference between the remaining book value and the estimated market value of those facilities. The actual market value of the plants has fluctuated over time. Recently, particularly in regard to coal and nuclear facilities, the value of those plants has declined. Some utilities seek either a return of those plants to rate base or a new long-term contract that is an economic equivalent. The benefits of such arrangements are cited to include providing a consumer hedge against price volatility, added levels of reliability, and resource diversity that has long term value. What do such movements of assets say about the viability of competitive markets? If the consumers benefits of price hedging, resource diversity, and so on are there what arrangements provide the most efficient way to obtain them? Should consumers get some credit for having already paid (in full or in part) either when they were in rate base, or through stranded asset payments? What effect, if any, will such arrangements have on retail choice? At the federal regulatory level, what impacts do such proposed contracts have on electricity energy and capacity markets? What impact should such arrangements have market pricing authority? Barbara Alexander, Consumer Affairs Consultant Michael Dowling, FirstEnergy Corporation William Mohl, Entergy John Shelk, Electric Power Supply Association HEPG Draft Agenda, March 10-11, 2016 Thursday, March 10 (cont’d) 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Lunch 1:15 pm Session Two. Stakeholder Processes: “The Worst Form of Government, except for All the Others” Organized markets under Regional Transmission Owners need a stakeholder process to consider and analyze all manner of reforms and improvements in market rules and operations. Although not strictly a democracy, the analogy is apt about the promise and complications of any governance mechanism that respects and draws on different or competing perspectives. The different experiences across RTOs allow for an examination of the functioning of stakeholder processes. How well are stakeholder processes working? What are the major examples of success and what are the examples of challenges? How have stakeholder processes evolved over time? Have stakeholder processes created so many committees and meetings that only the best funded of stakeholders can really influence outcomes as opposed to those with the best ideas? Have the stakeholder groups become more inclusive or exclusive? Who is the stakeholder that represents efficient markets? Are the RTOs susceptible to lobbying pressures and capture by certain interested stakeholders? What are the lessons and major opportunities for improvements? Are the processes too cumbersome, or just cumbersome enough? Dave Anders, PJM Interconnection Bruce Bleiweis, DC Energy Jeff Nelson, Southern California Edison Elizabeth Wilson, University of Minnesota 2:45 pm Coffee Break 3:00 pm Discussion 4:15 pm Adjourn 6:30 pm Reception and Dinner HEPG Draft Agenda, March 10-11, 2016 Friday, March 11 8:30 am Breakfast and Informal Discussion 9:00 am Session Three. Uneconomic Dispatch?: Frontier Challenges in Dispatch and Pricing The changing structure of dispatch to incorporate the challenges of electricity markets presents opportunities for reforms in operations and pricing. New work from the European experience points to dispatch problems from the constant cycling of flexible fossil units. Wear and tear, a cost that is familiar for regulation assets, now becomes a possibly material problem for load-following units working on a different time scale. The impact can include accelerated requirements for maintenance. Yet dispatch models do not account for these effects, and the prices don’t capture the costs. Other advances in dispatch and pricing give attention to the block loading and startup inflexibilities that require extended locational marginal pricing. What are the pressures that are driving dispatch models? How is the technology of renewables or conventional fossil plants changing to avoid or adapt to these new challenges? What generator, dispatch, pricing concerns might be pushing the envelope? Matthew Barmack, Calpine Corporation GE Representative Todd Ramey, Midcontinent ISO Sonja Wogrin, Universidad Pontificia Comillas 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Adjourn REGISTRATION FORM HEPG EIGHTY-SECOND PLENARY SESSION THURSDAY AND FRIDAY, MARCH 10-11, 2016 FOUR SEASONS GEORGETOWN WASHINGTON, DC TO: HARVARD ELECTRICITY POLICY GROUP John F. Kennedy School of Government FROM: Name Title Affiliation Address Phone E-mail ______YES, I will be able to attend the HEPG Plenary Session. ______ NO, I will not be able to attend the meeting. ______ I would like to send my designee: Name Title Address Phone E-mail ___________________________ ___________________________ ___________________________ ___________________________ ___________________________ ___________________________ HOTEL INFORMATION We have reserved a block of rooms at the Four Seasons for the evenings of Wednesday, March 9 and Thursday, March 10. Please arrange your reservation through Hannah Bruner in the Harvard Electricity Policy Group (Hannah_Bruner@hks.harvard.edu) by February 18. The Four Seasons is located at 2800 Pennsylvania Ave NW, Washington, DC 20007. To register for the session, please e-mail this reply form to: Hannah Bruner, HEPG Staff Assistant Email to: Hannah_Bruner@hks.harvard.edu From: To: Subject: Date: Attachments: Bruner, Hannah Beth L. Soliere Reimbursement for HEPG Conference Tuesday, December 15, 2015 1:54:08 PM missing_receipt.pdf HCOM_non-employee_reimbursement_form.pdf Dear Beth,   We are glad that Commissioner Stump was able to join us for our most recent conference, and we thank him for attending.   HEPG would like to reimburse him for his travel expenses.   Please follow the instructions below to submit Harvard’s required forms for reimbursement.               Reimbursement to the Commission:   1.      Itemized invoice   Reimbursement to Individual: 1.      Completed Non-Employee Reimbursement Form (Attached) 2.      Original receipts mailed to my attention at 79 JFK St., Box 84, Cambridge, MA 02139   Please let me know if you have any questions or need assistance completing the form.   Thank you, and have a wonderful holiday season.   Warm regards,     Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School Belfer 313 (617) 496-6760 Hannah_Bruner@hks.harvard.edu   HARVARD UNIVERSITY MISSING RECEIPT AFFIDAVIT Missing Receipt Affidavits lacking the required information or documentation will be returned to the authorized signer. Airline Tickets Attached is a copy of the itinerary invoice and proof of payment (i.e., credit card statement, cancelled check) Hotel Folio Attached is a copy of the hotel folio and proof of payment (i.e., credit card statement) -ORI certify that I have contacted the hotel and was unable to obtain a copy of the hotel folio. Please reimburse me based on the following information and proof of payment: Date # of nights Hotel/City Daily Rate Total Car Rental Agreement Attached is a copy of the car rental agreement and proof of payment (i.e., credit card statement) -ORI certify that I have contacted the rental car agency and was unable to obtain a copy of the car rental agreement Please reimburse me based on the following information and proof of payment: Dates Rental Company Car Class* # of Days Total *C=Compact, M=Mid-size, F= Full-size Date B, L, D* Meals (list each meal separately) Restaurant/City # of People** Total *B=Breakfast, L=Lunch, D=Dinner (**Name of attendees and business purpose is required on Expense Report or Pcard Settlement System) Miscellaneous For PCard transactions include a copy of the sweep report from the Pcard Settlement System or a copy of the credit card statement. Date Description (in detail) Total I, the undersigned, certify (a) that each expense described above, reported on Web Reimbursement Report ,or on the Pcard Settlement System Report was/were lost or not obtained, and (b) that number these expenses have not yet nor will again be submitted to Harvard University or any other organization for reimbursement or tax purposes. Signature of Payee/Card holder Authorized Signature REQUIRED REQUIRED Date Date ___ From: To: Subject: Date: Beth L. Soliere Bob Stump FW: HEPG Florida Agenda and Dinner Invitation Monday, December 07, 2015 1:49:39 PM FYI. I did request a room for you when I signed you up for this over a month ago. Not sure what happened on their end.   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Wednesday, December 02, 2015 9:43 AM To: Beth L. Soliere Cc: Bruner, Hannah Subject: RE: HEPG Florida Agenda and Dinner Invitation   Good morning Beth,   We look forward to Commissioner Stump being with us next week at the Harvard Electricity Policy Group session.  The commissioners will be staying at the Tideline Hotel, a lovely property adjacent to the conference hotel (Four Seasons Palm Beach) as the conference hotel has sold out.  The Tideline is located at  2842 S Ocean Blvd, Palm Beach, FL 33480.  The commissioner’s reservation number is:  15200122800, arriving 12/9 and departing on 12/11.   Best regards, Jo-Ann     Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu           From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Thursday, November 19, 2015 2:48 PM To: Mahoney, Jo-Ann Cc: Bruner, Hannah Subject: RE: HEPG Florida Agenda and Dinner Invitation   Hello,   I just want to confirm that you have Commissioner Stump down for a hotel room.   Thanks,   Beth   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Thursday, November 19, 2015 10:57 AM To: Mahoney, Jo-Ann Cc: Bruner, Hannah Subject: HEPG Florida Agenda and Dinner Invitation   We look forward to your participation in the upcoming Harvard Electricity Policy Group plenary session to be held in Palm Beach, Florida at the Four Seasons on Thursday-Friday, December 10-11.  Our current agenda, with confirmed speakers, is attached.   We will hold the conference reception and dinner at The historic Breakers on Thursday evening.  Transportation will be provided from the conference site.  You are welcome to bring a guest who is travelling with you.  Kindly RSVP to Hannah_Bruner@hks.harvard.edu.   Our best regards for the Thanksgiving Holiday.   See you in Florida, Jo-Ann   Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu     From: To: Subject: Date: Attachments: Bob Stump Beth L. Soliere Fwd: HEPG Logistics Friday, December 04, 2015 3:29:35 PM HEPG_12_15_DraftAgenda.docx ATT00001.htm I'll be attending with Jane Stump Sent from my iPhone Begin forwarded message: From: "Mahoney, Jo-Ann" Date: December 4, 2015 at 2:19:38 PM PST To: "Mahoney, Jo-Ann" Cc: "Bruner, Hannah" Subject: HEPG Logistics We look forward to seeing you next week at the HEPG meeting in Palm Beach to be held at the Four Seasons. Our agenda is attached.  Dress code will be business casual.  If you have not let Hannah Bruner know if you will be attending dinner on Thursday, December 10, kindly rsvp.    Best, Jo-Ann   Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu     HARVARD ELECTRICITY POLICY GROUP HARVARD ELECTRICITY POLICY GROUP EIGHTY-FIRST PLENARY SESSION The Four Seasons Palm Beach, FL THURSDAY AND FRIDAY, DECEMBER 10-11, 2015 DRAFT AGENDA Thursday, December 10 8:30 am Breakfast and Informal Discussion 9:00 am Session One. Transmission Expansion and Cost Allocation: Order 1000 Redux Transmission expansion and cost allocation protocols present continuing challenges for the evolution of electricity systems. Whether from the Clean Power Plan, direct support for renewables, or the changing patterns of generation and load, a central problem remains to adapt and provide workable rules for transmission expansion, both within and between regions, and the associated cost allocation requirements. Promulgation of Order 1000 in 2011 capped the development of the canonical regulation under FERC that has been subject of important Court challenges and continuing disputes. Everyone recognizes that a viable transmission expansion framework depends on a hybrid design that captures the complex interactions among new sources of supply within organized markets, between regions that reflect different organizations of the electricity system, and that interacts and supports both public policy objectives and the requirements of electricity markets. How is the experience with Order 1000 developing? What is the impact of “roughly commensurate” or “very roughly commensurate” cost allocation rules? What is the state of progress in implementing voluntary interregional expansion protocols to complement those mandatory compliance rules within regions? How are we doing on supporting efficient transmission investment? Moderator: Richard O’Neill, Federal Energy Regulatory Commission Henry Chao, New York ISO Bruce Edelston, Energy Policy Group Steve Huntoon, Energy Counsel PHONE 617-496-6760 FAX 617-495-1635 EMAIL HEPG@ksg.harvard.edu 79 John F. Kennedy Street, Box 84 Cambridge, Massachusetts 02138 www.hks.harvard.edu/hepg HEPG Draft Agenda, December 10-11, 2015 Thursday, December 10 (cont’d) 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Lunch 1:15 pm Session Two. Value of Solar: Shining Light on Hidden Values As we debate the appropriate method of pricing distributed solar generation, regulators are increasingly presented with studies on the Value of Solar which are designed to influence pricing decisions. It is often unclear whether the studies actually advocate using value of solar as a pricing methodology itself, or simply to put net metering in a proper perspective. To date, only Minnesota has adopted Value of Solar, as a means of pricing, but it did so only on a voluntary basis, and no utility has chosen to adopt it. The conclusions of the studies are widely varied. Support of rooftop solar often focuses on the “hidden values” and externality considerations inherent in distributed solar. Critics of net metering, focus on pricing anomalies/distortions, economic efficiency, and unintended socio/economic consequences. How relevant are such studies to the task of proper pricing of distributed solar? Is the Value of Solar debate déjà vu for the avoided cost, PURPA debates of the 1980’s? How should we look at the avoided costs associated with rooftop solar? Moderator: Catherine Sandoval, California Public Utilities Commission Ashley Brown, Harvard Electricity Policy Group Timothy James, Arizona State University Lynn Hinkle, Minnesota Solar Energy Industry Association Tommy Vitolo, Synapse Energy 2:45 pm Coffee Break 3:00 pm Discussion 4:15 pm Adjourn 6:30 pm Reception and Dinner The Breakers Palm Beach 1 S County Road, Palm Beach, FL 33480 Transportation will be provided from the Four Seasons at 6:15 pm. HEPG Draft Agenda, December 10-11, 2015 Friday, December 11 8:30 am Breakfast and Informal Discussion 9:00 am Session Three. Clean Power Plan: Critical State Implementation Decisions As states develop their implementation plans and various affected parties formulate their positions on how those plans should be designed, a dominant issue is whether the plan should be mass based or rate based. On the one hand, a mass-based approach could allow for compliance efforts to be carried out across a wide geographic area, which would lower overall costs. Ratebased approaches, on the other hand, allow for more explicit resource decisions, and may better protect, if not enhance, the value of assets controlled by existing clean energy suppliers. Players in the REC and SREC markets are likely to be quite cautious in trying to determine which option is most favorable to their portfolio, and to the long run impact on renewable credit markets. Demand side management and efficiency advocates may see advantages in a local rate based approach with better control as a tool for compliance. Would a rate based approach allow too much discretion that would turn compliance plans into a Christmas tree for various special interests? Would a mass based approach compromise local or state by state control and be insensitive to local impacts? How should states, in developing their SIP’s analyze the question of mass based or rate based approaches to compliance? What is the chance that different regulatory choices would result in a Balkanized grid with unintended consequences for electricity markets and environmental protection? Moderator: Anne Hoskins, Maryland Public Service Commission Jon Brekke, Great River Energy Michael Dowd, Virginia Department of Environmental Quality Rob Gramlich, American Wind Energy Association Doug Scott, Great Plains Institute 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Adjourn From: To: Cc: Subject: Date: Attachments: Mahoney, Jo-Ann Mahoney, Jo-Ann Bruner, Hannah HEPG Logistics Friday, December 04, 2015 3:19:59 PM HEPG_12_15_DraftAgenda.docx We look forward to seeing you next week at the HEPG meeting in Palm Beach to be held at the Four Seasons. Our agenda is attached.  Dress code will be business casual.  If you have not let Hannah Bruner know if you will be attending dinner on Thursday, December 10, kindly rsvp.    Best, Jo-Ann   Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu     HARVARD ELECTRICITY POLICY GROUP HARVARD ELECTRICITY POLICY GROUP EIGHTY-FIRST PLENARY SESSION The Four Seasons Palm Beach, FL THURSDAY AND FRIDAY, DECEMBER 10-11, 2015 DRAFT AGENDA Thursday, December 10 8:30 am Breakfast and Informal Discussion 9:00 am Session One. Transmission Expansion and Cost Allocation: Order 1000 Redux Transmission expansion and cost allocation protocols present continuing challenges for the evolution of electricity systems. Whether from the Clean Power Plan, direct support for renewables, or the changing patterns of generation and load, a central problem remains to adapt and provide workable rules for transmission expansion, both within and between regions, and the associated cost allocation requirements. Promulgation of Order 1000 in 2011 capped the development of the canonical regulation under FERC that has been subject of important Court challenges and continuing disputes. Everyone recognizes that a viable transmission expansion framework depends on a hybrid design that captures the complex interactions among new sources of supply within organized markets, between regions that reflect different organizations of the electricity system, and that interacts and supports both public policy objectives and the requirements of electricity markets. How is the experience with Order 1000 developing? What is the impact of “roughly commensurate” or “very roughly commensurate” cost allocation rules? What is the state of progress in implementing voluntary interregional expansion protocols to complement those mandatory compliance rules within regions? How are we doing on supporting efficient transmission investment? Moderator: Richard O’Neill, Federal Energy Regulatory Commission Henry Chao, New York ISO Bruce Edelston, Energy Policy Group Steve Huntoon, Energy Counsel PHONE 617-496-6760 FAX 617-495-1635 EMAIL HEPG@ksg.harvard.edu 79 John F. Kennedy Street, Box 84 Cambridge, Massachusetts 02138 www.hks.harvard.edu/hepg HEPG Draft Agenda, December 10-11, 2015 Thursday, December 10 (cont’d) 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Lunch 1:15 pm Session Two. Value of Solar: Shining Light on Hidden Values As we debate the appropriate method of pricing distributed solar generation, regulators are increasingly presented with studies on the Value of Solar which are designed to influence pricing decisions. It is often unclear whether the studies actually advocate using value of solar as a pricing methodology itself, or simply to put net metering in a proper perspective. To date, only Minnesota has adopted Value of Solar, as a means of pricing, but it did so only on a voluntary basis, and no utility has chosen to adopt it. The conclusions of the studies are widely varied. Support of rooftop solar often focuses on the “hidden values” and externality considerations inherent in distributed solar. Critics of net metering, focus on pricing anomalies/distortions, economic efficiency, and unintended socio/economic consequences. How relevant are such studies to the task of proper pricing of distributed solar? Is the Value of Solar debate déjà vu for the avoided cost, PURPA debates of the 1980’s? How should we look at the avoided costs associated with rooftop solar? Moderator: Catherine Sandoval, California Public Utilities Commission Ashley Brown, Harvard Electricity Policy Group Timothy James, Arizona State University Lynn Hinkle, Minnesota Solar Energy Industry Association Tommy Vitolo, Synapse Energy 2:45 pm Coffee Break 3:00 pm Discussion 4:15 pm Adjourn 6:30 pm Reception and Dinner The Breakers Palm Beach 1 S County Road, Palm Beach, FL 33480 Transportation will be provided from the Four Seasons at 6:15 pm. HEPG Draft Agenda, December 10-11, 2015 Friday, December 11 8:30 am Breakfast and Informal Discussion 9:00 am Session Three. Clean Power Plan: Critical State Implementation Decisions As states develop their implementation plans and various affected parties formulate their positions on how those plans should be designed, a dominant issue is whether the plan should be mass based or rate based. On the one hand, a mass-based approach could allow for compliance efforts to be carried out across a wide geographic area, which would lower overall costs. Ratebased approaches, on the other hand, allow for more explicit resource decisions, and may better protect, if not enhance, the value of assets controlled by existing clean energy suppliers. Players in the REC and SREC markets are likely to be quite cautious in trying to determine which option is most favorable to their portfolio, and to the long run impact on renewable credit markets. Demand side management and efficiency advocates may see advantages in a local rate based approach with better control as a tool for compliance. Would a rate based approach allow too much discretion that would turn compliance plans into a Christmas tree for various special interests? Would a mass based approach compromise local or state by state control and be insensitive to local impacts? How should states, in developing their SIP’s analyze the question of mass based or rate based approaches to compliance? What is the chance that different regulatory choices would result in a Balkanized grid with unintended consequences for electricity markets and environmental protection? Moderator: Anne Hoskins, Maryland Public Service Commission Jon Brekke, Great River Energy Michael Dowd, Virginia Department of Environmental Quality Rob Gramlich, American Wind Energy Association Doug Scott, Great Plains Institute 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Adjourn From: To: Subject: Date: Bruner, Hannah Beth L. Soliere RE: HEPG Florida Agenda and Dinner Invitation Friday, November 20, 2015 8:54:23 AM Good morning, Beth, Yes—Commissioner Stump has a room. Have a great weekend. Best wishes, Hannah   From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Thursday, November 19, 2015 2:48 PM To: Mahoney, Jo-Ann Cc: Bruner, Hannah Subject: RE: HEPG Florida Agenda and Dinner Invitation   Hello,   I just want to confirm that you have Commissioner Stump down for a hotel room.   Thanks,   Beth   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Thursday, November 19, 2015 10:57 AM To: Mahoney, Jo-Ann Cc: Bruner, Hannah Subject: HEPG Florida Agenda and Dinner Invitation   We look forward to your participation in the upcoming Harvard Electricity Policy Group plenary session to be held in Palm Beach, Florida at the Four Seasons on Thursday-Friday, December 10-11.  Our current agenda, with confirmed speakers, is attached.   We will hold the conference reception and dinner at The historic Breakers on Thursday evening.  Transportation will be provided from the conference site.  You are welcome to bring a guest who is travelling with you.  Kindly RSVP to Hannah_Bruner@hks.harvard.edu.   Our best regards for the Thanksgiving Holiday.   See you in Florida, Jo-Ann   Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617?495?1390 From: To: Subject: Date: Attachments: Bob Stump Beth L. Soliere Fwd: HEPG Florida Agenda and Dinner Invitation Thursday, November 19, 2015 11:14:22 AM HEPG_12_15_DraftAgenda.docx ATT00001.htm Sent from my iPhone Begin forwarded message: From: "Mahoney, Jo-Ann" Date: November 19, 2015 at 10:57:14 AM MST To: "Mahoney, Jo-Ann" Cc: "Bruner, Hannah" Subject: HEPG Florida Agenda and Dinner Invitation We look forward to your participation in the upcoming Harvard Electricity Policy Group plenary session to be held in Palm Beach, Florida at the Four Seasons on ThursdayFriday, December 10-11.  Our current agenda, with confirmed speakers, is attached.   We will hold the conference reception and dinner at The historic Breakers on Thursday evening.  Transportation will be provided from the conference site.  You are welcome to bring a guest who is travelling with you.  Kindly RSVP to Hannah_Bruner@hks.harvard.edu.   Our best regards for the Thanksgiving Holiday.   See you in Florida, Jo-Ann   Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu     HARVARD ELECTRICITY POLICY GROUP HARVARD ELECTRICITY POLICY GROUP EIGHTY-FIRST PLENARY SESSION The Four Seasons Palm Beach, FL THURSDAY AND FRIDAY, DECEMBER 10-11, 2015 DRAFT AGENDA Thursday, December 10 8:30 am Breakfast and Informal Discussion 9:00 am Session One. Transmission Expansion and Cost Allocation: Order 1000 Redux Transmission expansion and cost allocation protocols present continuing challenges for the evolution of electricity systems. Whether from the Clean Power Plan, direct support for renewables, or the changing patterns of generation and load, a central problem remains to adapt and provide workable rules for transmission expansion, both within and between regions, and the associated cost allocation requirements. Promulgation of Order 1000 in 2011 capped the development of the canonical regulation under FERC that has been subject of important Court challenges and continuing disputes. Everyone recognizes that a viable transmission expansion framework depends on a hybrid design that captures the complex interactions among new sources of supply within organized markets, between regions that reflect different organizations of the electricity system, and that interacts and supports both public policy objectives and the requirements of electricity markets. How is the experience with Order 1000 developing? What is the impact of “roughly commensurate” or “very roughly commensurate” cost allocation rules? What is the state of progress in implementing voluntary interregional expansion protocols to complement those mandatory compliance rules within regions? How are we doing on supporting efficient transmission investment? Moderator: Richard O’Neill, Federal Energy Regulatory Commission Henry Chao, New York ISO Bruce Edelston, Energy Policy Group Steve Huntoon, Energy Council Peggy Simmons, American Electric Power PHONE 617-496-6760 FAX 617-495-1635 EMAIL HEPG@ksg.harvard.edu 79 John F. Kennedy Street, Box 84 Cambridge, Massachusetts 02138 www.hks.harvard.edu/hepg HEPG Draft Agenda, December 10-11, 2015 Thursday, December 10 (cont’d) 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Lunch 1:15 pm Session Two. Value of Solar: Shining Light on Hidden Values As we debate the appropriate method of pricing distributed solar generation, regulators are increasingly presented with studies on the Value of Solar which are designed to influence pricing decisions. It is often unclear whether the studies actually advocate using value of solar as a pricing methodology itself, or simply to put net metering in a proper perspective. To date, only Minnesota has adopted Value of Solar, as a means of pricing, but it did so only on a voluntary basis, and no utility has chosen to adopt it. The conclusions of the studies are widely varied. Support of rooftop solar often focuses on the “hidden values” and externality considerations inherent in distributed solar. Critics of net metering, focus on pricing anomalies/distortions, economic efficiency, and unintended socio/economic consequences. How relevant are such studies to the task of proper pricing of distributed solar? Is the Value of Solar debate déjà vu for the avoided cost, PURPA debates of the 1980’s? How should we look at the avoided costs associated with rooftop solar? Timothy James, Arizona State University Lynn Hinkle, Minnesota Solar Energy Industry Association Tommy Vitolo, Synapse Energy 2:45 pm Coffee Break 3:00 pm Discussion 4:15 pm Adjourn 6:30 pm Reception and Dinner The Breakers Palm Beach 1 S County Road, Palm Beach, FL 33480 Transportation will be provided from the Four Seasons at 6:15 pm. HEPG Draft Agenda, December 10-11, 2015 Friday, December 11 8:30 am Breakfast and Informal Discussion 9:00 am Session Three. Clean Power Plan: Critical State Implementation Decisions As states develop their implementation plans and various affected parties formulate their positions on how those plans should be designed, a dominant issue is whether the plan should be mass based or rate based. On the one hand, a mass-based approach could allow for compliance efforts to be carried out across a wide geographic area, which would lower overall costs. Ratebased approaches, on the other hand, allow for more explicit resource decisions, and may better protect, if not enhance, the value of assets controlled by existing clean energy suppliers. Players in the REC and SREC markets are likely to be quite cautious in trying to determine which option is most favorable to their portfolio, and to the long run impact on renewable credit markets. Demand side management and efficiency advocates may see advantages in a local rate based approach with better control as a tool for compliance. Would a rate based approach allow too much discretion that would turn compliance plans into a Christmas tree for various special interests? Would a mass based approach compromise local or state by state control and be insensitive to local impacts? How should states, in developing their SIP’s analyze the question of mass based or rate based approaches to compliance? What is the chance that different regulatory choices would result in a Balkanized grid with unintended consequences for electricity markets and environmental protection? Moderator: Anne Hoskins, Maryland Public Service Commission Jon Brekke, Great River Energy Michael Dowd, Virginia Department of Environmental Quality Rob Gramlich, American Wind Energy Association Doug Scott, Great Plains Institute 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Adjourn From: To: Subject: Date: Beth L. Soliere Bob Stump RE: HEPG"s December Conference Thursday, November 05, 2015 11:00:10 AM Ok.  I just remember last year December was a crazy OM month, but it will probably be fine.   From: Bob Stump Sent: Thursday, November 05, 2015 10:59 AM To: Beth L. Soliere Subject: Re: HEPG's December Conference   Susan attends at times I think. We should be fine.  Sent from my iPhone On Nov 5, 2015, at 10:58 AM, Beth L. Soliere wrote: OM is the 8th and 9th.  Should we just assume it won’t go over to the 9th or I guess you could just fly out after if it did go over?   From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Wednesday, November 04, 2015 2:56 PM Subject: HEPG's December Conference   Good afternoon,   The Harvard Electricity Policy Group’s next session will take place in Palm Beach, FL on Thursday and Friday, December 10 and 11 at the Four Seasons. We cordially invite you to attend.   HEPG has reserved a block of rooms at the Four Seasons for the evenings of Wednesday, December 9 and Thursday, December 10. I will be happy to make arrangements for your stay. However, please note that the Four Seasons has set the reservation deadline for Friday, November 13.   As is customary, the session will convene at breakfast on Thursday, December 10 and adjourn at noon on Friday, December 11. On Thursday evening, we will hold a conference reception and dinner.   We are pleased to announce the topics for the October meeting:   Clean Power Plan: Critical State Implementation Decisions   As states develop their implementation plans and various affected parties formulate their positions on how those plans should be designed, a dominant issue is whether the plan should be mass based or rate based. On the one hand, a mass-based approach could allow for compliance efforts to be carried out across a wide geographic area, which would lower overall costs.  Rate-based approaches, on the other hand, allow for more explicit resource decisions, and may better protect, if not enhance, the value of assets controlled by existing clean energy suppliers. Players in the REC and SREC markets are likely to be quite cautious in trying to determine which option is most favorable to their portfolio, and to the long run impact on renewable credit markets.  Demand side management and efficiency advocates may see advantages in a local rate based approach with better control as a tool for compliance. Would a rate based approach allow too much discretion that would turn compliance plans into a Christmas tree for various special interests? Would a mass based approach compromise local or state by state control and be insensitive to local impacts?  How should states, in developing their SIP’s analyze the question of mass based or rate based approaches to compliance?  What is the chance that different regulatory choices would result in a Balkanized grid with unintended consequences for electricity markets and environmental protection?   Value of Solar: Shining Light on Hidden Values   As we debate the appropriate method of pricing distributed solar generations, regulators are increasingly presented with studies on the Value of Solar which are designed to influence pricing decisions.  It is often unclear whether the studies actually advocate using value of solar as a pricing methodology itself, or simply to put net metering in a proper perspective.  To date, only Minnesota has adopted Value of Solar, as a means of pricing, but it did so only on a voluntary basis, and no utility has chosen to adopt it.   The conclusions of the studies are widely varied.  Support of rooftop solar often focuses on the “hidden values” and externality considerations inherent in distributed solar.  Critics of net metering, focus on pricing anomalies/distortions, economic efficiency, and unintended socio/economic consequences. How relevant are such studies to the task of proper pricing of distributed solar? Is the Value of Solar debate déjà vu for the avoided cost, PURPA debates of the 1980’s?  How should we look at the avoided costs associated with rooftop solar?   Transmission Expansion and Cost Allocation: Order 1000 Redux   Transmission expansion and cost allocation protocols present continuing challenges for the evolution of electricity systems.  Whether from the Clean Power Plan, direct support for renewables, or the changing patterns of generation and load, a central problem remains to adapt and provide workable rules for transmission expansion, both within and between regions, and the associated cost allocation requirements.  Promulgation of Order 1000 in 2011 capped the development of the canonical regulation under FERC that has been subject of important Court challenges and continuing disputes.  Everyone recognizes that a viable transmission expansion framework depends on a hybrid design that captures the complex interactions among new sources of supply within organized markets, between regions that reflect different organizations of the electricity system, and that interacts and supports both public policy objectives and the requirements of electricity markets.  How is the experience with Order 1000 developing?  What is the impact of “roughly commensurate” or “very roughly commensurate” cost allocation rules?  What is the state of progress in implementing voluntary interregional expansion protocols to complement that mandatory compliance rules within regions?  How are we doing on supporting efficient transmission investment?   Please do not hesitate to contact me if you have any questions or concerns. I look forward to your response and hope you will join us in Palm Beach.   Have a lovely weekend.   Warm regards,   Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu   From: To: Cc: Subject: Date: Bob Stump Bruner, Hannah Beth L. Soliere Re: HEPG"s December Conference Wednesday, November 04, 2015 2:58:25 PM Thanks, Hannah. Looking forward.  Bob Sent from my iPhone On Nov 4, 2015, at 2:57 PM, Bruner, Hannah wrote: Good afternoon,   The Harvard Electricity Policy Group’s next session will take place in Palm Beach, FL on Thursday and Friday, December 10 and 11 at the Four Seasons. We cordially invite you to attend.   HEPG has reserved a block of rooms at the Four Seasons for the evenings of Wednesday, December 9 and Thursday, December 10. I will be happy to make arrangements for your stay. However, please note that the Four Seasons has set the reservation deadline for Friday, November 13.   As is customary, the session will convene at breakfast on Thursday, December 10 and adjourn at noon on Friday, December 11. On Thursday evening, we will hold a conference reception and dinner.   We are pleased to announce the topics for the October meeting:   Clean Power Plan: Critical State Implementation Decisions   As states develop their implementation plans and various affected parties formulate their positions on how those plans should be designed, a dominant issue is whether the plan should be mass based or rate based. On the one hand, a mass-based approach could allow for compliance efforts to be carried out across a wide geographic area, which would lower overall costs.  Rate-based approaches, on the other hand, allow for more explicit resource decisions, and may better protect, if not enhance, the value of assets controlled by existing clean energy suppliers. Players in the REC and SREC markets are likely to be quite cautious in trying to determine which option is most favorable to their portfolio, and to the long run impact on renewable credit markets.  Demand side management and efficiency advocates may see advantages in a local rate based approach with better control as a tool for compliance. Would a rate based approach allow too much discretion that would turn compliance plans into a Christmas tree for various special interests? Would a mass based approach compromise local or state by state control and be insensitive to local impacts?  How should states, in developing their SIP’s analyze the question of mass based or rate based approaches to compliance?  What is the chance that different regulatory choices would result in a Balkanized grid with unintended consequences for electricity markets and environmental protection?   Value of Solar: Shining Light on Hidden Values   As we debate the appropriate method of pricing distributed solar generations, regulators are increasingly presented with studies on the Value of Solar which are designed to influence pricing decisions.  It is often unclear whether the studies actually advocate using value of solar as a pricing methodology itself, or simply to put net metering in a proper perspective.  To date, only Minnesota has adopted Value of Solar, as a means of pricing, but it did so only on a voluntary basis, and no utility has chosen to adopt it.   The conclusions of the studies are widely varied.  Support of rooftop solar often focuses on the “hidden values” and externality considerations inherent in distributed solar.  Critics of net metering, focus on pricing anomalies/distortions, economic efficiency, and unintended socio/economic consequences. How relevant are such studies to the task of proper pricing of distributed solar? Is the Value of Solar debate déjà vu for the avoided cost, PURPA debates of the 1980’s?  How should we look at the avoided costs associated with rooftop solar?   Transmission Expansion and Cost Allocation: Order 1000 Redux   Transmission expansion and cost allocation protocols present continuing challenges for the evolution of electricity systems.  Whether from the Clean Power Plan, direct support for renewables, or the changing patterns of generation and load, a central problem remains to adapt and provide workable rules for transmission expansion, both within and between regions, and the associated cost allocation requirements.  Promulgation of Order 1000 in 2011 capped the development of the canonical regulation under FERC that has been subject of important Court challenges and continuing disputes.  Everyone recognizes that a viable transmission expansion framework depends on a hybrid design that captures the complex interactions among new sources of supply within organized markets, between regions that reflect different organizations of the electricity system, and that interacts and supports both public policy objectives and the requirements of electricity markets.  How is the experience with Order 1000 developing?  What is the impact of “roughly commensurate” or “very roughly commensurate” cost allocation rules?  What is the state of progress in implementing voluntary interregional expansion protocols to complement that mandatory compliance rules within regions?  How are we doing on supporting efficient transmission investment?   Please do not hesitate to contact me if you have any questions or concerns. I look forward to your response and hope you will join us in Palm Beach.   Have a lovely weekend.   Warm regards,   Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu   From: Subject: Date: Attachments: Bruner, Hannah HEPG"s December Conference Wednesday, November 04, 2015 2:57:46 PM Commissioner Registration Form.docx Good afternoon,   The Harvard Electricity Policy Group’s next session will take place in Palm Beach, FL on Thursday and Friday, December 10 and 11 at the Four Seasons. We cordially invite you to attend.   HEPG has reserved a block of rooms at the Four Seasons for the evenings of Wednesday, December 9 and Thursday, December 10. I will be happy to make arrangements for your stay. However, please note that the Four Seasons has set the reservation deadline for Friday, November 13.   As is customary, the session will convene at breakfast on Thursday, December 10 and adjourn at noon on Friday, December 11. On Thursday evening, we will hold a conference reception and dinner.   We are pleased to announce the topics for the October meeting:   Clean Power Plan: Critical State Implementation Decisions   As states develop their implementation plans and various affected parties formulate their positions on how those plans should be designed, a dominant issue is whether the plan should be mass based or rate based. On the one hand, a mass-based approach could allow for compliance efforts to be carried out across a wide geographic area, which would lower overall costs.  Rate-based approaches, on the other hand, allow for more explicit resource decisions, and may better protect, if not enhance, the value of assets controlled by existing clean energy suppliers. Players in the REC and SREC markets are likely to be quite cautious in trying to determine which option is most favorable to their portfolio, and to the long run impact on renewable credit markets.  Demand side management and efficiency advocates may see advantages in a local rate based approach with better control as a tool for compliance. Would a rate based approach allow too much discretion that would turn compliance plans into a Christmas tree for various special interests? Would a mass based approach compromise local or state by state control and be insensitive to local impacts?  How should states, in developing their SIP’s analyze the question of mass based or rate based approaches to compliance?  What is the chance that different regulatory choices would result in a Balkanized grid with unintended consequences for electricity markets and environmental protection?   Value of Solar: Shining Light on Hidden Values   As we debate the appropriate method of pricing distributed solar generations, regulators are increasingly presented with studies on the Value of Solar which are designed to influence pricing decisions.  It is often unclear whether the studies actually advocate using value of solar as a pricing methodology itself, or simply to put net metering in a proper perspective.  To date, only Minnesota has adopted Value of Solar, as a means of pricing, but it did so only on a voluntary basis, and no utility has chosen to adopt it.   The conclusions of the studies are widely varied.  Support of rooftop solar often focuses on the “hidden values” and externality considerations inherent in distributed solar.  Critics of net metering, focus on pricing anomalies/distortions, economic efficiency, and unintended socio/economic consequences. How relevant are such studies to the task of proper pricing of distributed solar? Is the Value of Solar debate déjà vu for the avoided cost, PURPA debates of the 1980’s?  How should we look at the avoided costs associated with rooftop solar?   Transmission Expansion and Cost Allocation: Order 1000 Redux   Transmission expansion and cost allocation protocols present continuing challenges for the evolution of electricity systems.  Whether from the Clean Power Plan, direct support for renewables, or the changing patterns of generation and load, a central problem remains to adapt and provide workable rules for transmission expansion, both within and between regions, and the associated cost allocation requirements.  Promulgation of Order 1000 in 2011 capped the development of the canonical regulation under FERC that has been subject of important Court challenges and continuing disputes.  Everyone recognizes that a viable transmission expansion framework depends on a hybrid design that captures the complex interactions among new sources of supply within organized markets, between regions that reflect different organizations of the electricity system, and that interacts and supports both public policy objectives and the requirements of electricity markets.  How is the experience with Order 1000 developing?  What is the impact of “roughly commensurate” or “very roughly commensurate” cost allocation rules?  What is the state of progress in implementing voluntary interregional expansion protocols to complement that mandatory compliance rules within regions?  How are we doing on supporting efficient transmission investment?   Please do not hesitate to contact me if you have any questions or concerns. I look forward to your response and hope you will join us in Palm Beach.   Have a lovely weekend.   Warm regards,   Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu   REGISTRATION FORM HEPG EIGHTY-FIRST PLENARY SESSION THURSDAY AND FRIDAY, DECEMBER 10-11, 2015 FOUR SEASONS RESORT PALM BEACH, FL TO: HARVARD ELECTRICITY POLICY GROUP John F. Kennedy School of Government FROM: Name Title Affiliation Address Phone E-mail ______YES, I will be able to attend the HEPG Plenary Session. ______ NO, I will not be able to attend the meeting. ______ I would like to send my designee: Name Title Address Phone E-mail ___________________________ ___________________________ ___________________________ ___________________________ ___________________________ ___________________________ HOTEL INFORMATION We have reserved a block of rooms at the Four Seasons for the evenings of Wednesday, December 9 and Thursday, December 10. Please arrange your reservation through Hannah Bruner in the Harvard Electricity Policy Group (Hannah_Bruner@hks.harvard.edu) by Monday, November 13. The Four Seasons is located at 2800 South Ocean Blvd, Palm Beach, FL 33480. To register for the session, please fax or e-mail this reply form to: Jo-Ann Mahoney, HEPG Program Director Fax: (617) 495-1635 Email to: Hannah_Bruner@hks.harvard.edu From: To: Subject: Date: Attachments: Beth L. Soliere Bob Stump FW: HEPG Dinner and Agenda Wednesday, September 30, 2015 9:08:14 AM HEPG_10_15_DraftAgenda w Speakers.docx They probably sent this to you but here is the draft agenda.   From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Friday, September 18, 2015 11:11 AM Subject: HEPG Dinner and Agenda   Good afternoon, We look forward to seeing you in Houston for the upcoming meeting of the Harvard Electricity Policy Group.  Please find attached the Draft Agenda for the session. The conference reception and dinner will be held on Thursday, October 1 on site at the historic manor house. The chef is preparing a creole dinner. Kindly RSVP to Hannah_Bruner@hks.harvard.edu by Wednesday, September 23. Have a lovely weekend. Best regards,   Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu       Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu   HARVARD ELECTRICITY POLICY GROUP HARVARD ELECTRICITY POLICY GROUP EIGHTIETH PLENARY SESSION The Houstonian Houston, TX THURSDAY AND FRIDAY, OCTOBER 1-2, 2015 DRAFT AGENDA Thursday, October 1 8:30 am Breakfast and Informal Discussion 9:00 am Session One. Computational Frontiers in Electricity Markets: Not Your Grandfather’s Economic Dispatch The long development of sophisticated software for economic dispatch created a foundational framework for organized electricity markets. Absent the computational tools, developed well before the era of electricity market reform, the fundamental design found in all organized electricity markets in the United States would have been no more than an ivory tower aspiration. The early development of markets fully exploited these tools, and their existence disposed of otherwise powerful arguments against open access markets operated under principles of non-discrimination. Since then, two parallel developments have advanced the capabilities and the need for better computational environments. First, the software has gotten better, in some cases, much better. For example, formal optimization for unit commitment was beyond the capability of the early economic dispatch models, but is now available and allows for improvements in market efficiency and market design. Second, the demand for new market products and expanded markets is increasing rapidly. For instance, the interest in exploiting distributed resources may fit in the framework of economic dispatch, but at an unprecedented scale compared to the existing wholesale markets for bulk generation. What are the expanded capabilities of the software? How does this improvement in software change the scope and reach of electricity markets? How could and should better software change electricity market design? What are the limits of the frontier tools? Are proposals for greatly expanded markets and markets products constrained by unrecognized challenges of big data and big optimization? Robert Bixby, Gurobi Optimization Michael Caramanis, Boston University Richard O’Neill, Federal Energy Regulatory Commission Sainath Moorty, Electric Reliability Council of Texas PHONE 617-496-6760 FAX 617-495-1635 EMAIL HEPG@ksg.harvard.edu 79 John F. Kennedy Street, Box 84 Cambridge, Massachusetts 02138 www.hks.harvard.edu/hepg HEPG Draft Agenda, October 1-2, 2015 Thursday, October 1 (cont’d) 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Lunch 1:15 pm Session Two. Free Renewables and Electricity Markets: Can Renewables Thrive Through Markets? Advocates suggest that we can move fully to an electricity system with only renewable sources of energy. Many counter that it is virtually impossible because of the intermittent nature of the wind and solar. Even with a solution for the intermittency problem, however, are there other inherent economic constraints on renewable penetration? Are free renewables, that have near zero short-run marginal costs, a special case that undermines the electricity market? Will subsidies be required in perpetuity, particularly if the value of the energy produced decreases faster than the cost as renewable capacity increases? Does high market penetration of renewables lead inexorably to a declining marginal values, leading to rapid growth of subsidies? Are the social benefits associated with high penetration of renewables sufficient to justify the subsidies? Are subsidies best provided through mandatory financial arrangements rather than by a voluntary equilibrium of the market? Why is electricity market design important? With high renewables penetration, what are the implications for electricity market design? Stephen Brick, Clean Air Task Force Michael Hogan, Regulatory Assistance Project Thomas-Olivier Léautier, Toulouse School of Economics Alex Trembath, The Breakthrough Institute 2:45 pm Coffee Break 3:00 pm Discussion 4:15 pm Adjourn 6:30 pm Reception and Dinner, The Manor House HEPG Draft Agenda, October 1-2, 2015 Friday, October 2 8:30 am Breakfast and Informal Discussion 9:00 am Session Three. EPA Clean Power Plan: What Now? After receiving a huge volume of comments on its proposed rules, EPA issued its Section 111(d) final regulations in the Clean Power Plan. The agency’s pronouncements are already being critiqued substantively and challenged both politically and legally. The final rule setting emission guidelines includes important changes from the proposal. In looking forward, it would be useful to first look at what changed from the proposal the agency first published and the final rules, and why. What motivated the changes, and what, if anything, did they accomplish? What is the significance, for example, of the reduction of building blocks from 4 to 3? Is the impact on the various states different from the original to the final version, and what is the import of that? Going forward, what are the relative strengths and weaknesses of the rules from a substantive point of view (i.e. how effective will it be in cost effective carbon emissions reduction?)? What are the most significant legal vulnerabilities of the rules, and what are the probabilities of success for such challenges? If successful, what remedies are the Courts likely to impose? If upheld by the Courts, what will be the main implementation challenges? How should electricity market participants respond in this new world? Moderator: Lawrence Makovich, HEPG, IHS Bill Scherman, Gibson Dunn Paul Sotkiewicz, PJM Interconnection Michael Wara, Stanford Law School Jürgen Weiss, The Brattle Group 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Adjourn From: To: Subject: Date: Bob Stump Beth L. Soliere Re: Hepg Tuesday, September 22, 2015 12:44:35 PM Tom, is this you or Beth, did you cut and paste? It starts at 8:30 or 8 on the 1st, I assume. So I'd leave on the 29th or very early on the 1st. They cover two nights as always, right? Sent from my iPhone > On Sep 22, 2015, at 3:41 PM, Beth L. Soliere wrote: > > It's starts on October 1st and ends on the 2nd. So 30th to 2nd. > > Regards, Tom Broderick > >> On Sep 22, 2015, at 12:35 PM, Bob Stump wrote: >> >> Need to get the ticket today. So I Leave the 29th and return the 2nd? >> >> Sent from my iPhone From: To: Subject: Date: Beth L. Soliere Bob Stump Re: Hepg Tuesday, September 22, 2015 12:41:52 PM It's starts on October 1st and ends on the 2nd. So 30th to 2nd. Regards, Tom Broderick > On Sep 22, 2015, at 12:35 PM, Bob Stump wrote: > > Need to get the ticket today. So I Leave the 29th and return the 2nd? > > Sent from my iPhone From: Subject: Date: Attachments: Bruner, Hannah HEPG Dinner and Agenda Friday, September 18, 2015 11:12:16 AM HEPG_10_15_DraftAgenda w Speakers.docx Good afternoon, We look forward to seeing you in Houston for the upcoming meeting of the Harvard Electricity Policy Group.  Please find attached the Draft Agenda for the session. The conference reception and dinner will be held on Thursday, October 1 on site at the historic manor house. The chef is preparing a creole dinner. Kindly RSVP to Hannah_Bruner@hks.harvard.edu by Wednesday, September 23. Have a lovely weekend. Best regards,   Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu       Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu   HARVARD ELECTRICITY POLICY GROUP HARVARD ELECTRICITY POLICY GROUP EIGHTIETH PLENARY SESSION The Houstonian Houston, TX THURSDAY AND FRIDAY, OCTOBER 1-2, 2015 DRAFT AGENDA Thursday, October 1 8:30 am Breakfast and Informal Discussion 9:00 am Session One. Computational Frontiers in Electricity Markets: Not Your Grandfather’s Economic Dispatch The long development of sophisticated software for economic dispatch created a foundational framework for organized electricity markets. Absent the computational tools, developed well before the era of electricity market reform, the fundamental design found in all organized electricity markets in the United States would have been no more than an ivory tower aspiration. The early development of markets fully exploited these tools, and their existence disposed of otherwise powerful arguments against open access markets operated under principles of non-discrimination. Since then, two parallel developments have advanced the capabilities and the need for better computational environments. First, the software has gotten better, in some cases, much better. For example, formal optimization for unit commitment was beyond the capability of the early economic dispatch models, but is now available and allows for improvements in market efficiency and market design. Second, the demand for new market products and expanded markets is increasing rapidly. For instance, the interest in exploiting distributed resources may fit in the framework of economic dispatch, but at an unprecedented scale compared to the existing wholesale markets for bulk generation. What are the expanded capabilities of the software? How does this improvement in software change the scope and reach of electricity markets? How could and should better software change electricity market design? What are the limits of the frontier tools? Are proposals for greatly expanded markets and markets products constrained by unrecognized challenges of big data and big optimization? Robert Bixby, Gurobi Optimization Michael Caramanis, Boston University Richard O’Neill, Federal Energy Regulatory Commission Sainath Moorty, Electric Reliability Council of Texas PHONE 617-496-6760 FAX 617-495-1635 EMAIL HEPG@ksg.harvard.edu 79 John F. Kennedy Street, Box 84 Cambridge, Massachusetts 02138 www.hks.harvard.edu/hepg HEPG Draft Agenda, October 1-2, 2015 Thursday, October 1 (cont’d) 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Lunch 1:15 pm Session Two. Free Renewables and Electricity Markets: Can Renewables Thrive Through Markets? Advocates suggest that we can move fully to an electricity system with only renewable sources of energy. Many counter that it is virtually impossible because of the intermittent nature of the wind and solar. Even with a solution for the intermittency problem, however, are there other inherent economic constraints on renewable penetration? Are free renewables, that have near zero short-run marginal costs, a special case that undermines the electricity market? Will subsidies be required in perpetuity, particularly if the value of the energy produced decreases faster than the cost as renewable capacity increases? Does high market penetration of renewables lead inexorably to a declining marginal values, leading to rapid growth of subsidies? Are the social benefits associated with high penetration of renewables sufficient to justify the subsidies? Are subsidies best provided through mandatory financial arrangements rather than by a voluntary equilibrium of the market? Why is electricity market design important? With high renewables penetration, what are the implications for electricity market design? Stephen Brick, Clean Air Task Force Michael Hogan, Regulatory Assistance Project Thomas-Olivier Léautier, Toulouse School of Economics Alex Trembath, The Breakthrough Institute 2:45 pm Coffee Break 3:00 pm Discussion 4:15 pm Adjourn 6:30 pm Reception and Dinner, The Manor House HEPG Draft Agenda, October 1-2, 2015 Friday, October 2 8:30 am Breakfast and Informal Discussion 9:00 am Session Three. EPA Clean Power Plan: What Now? After receiving a huge volume of comments on its proposed rules, EPA issued its Section 111(d) final regulations in the Clean Power Plan. The agency’s pronouncements are already being critiqued substantively and challenged both politically and legally. The final rule setting emission guidelines includes important changes from the proposal. In looking forward, it would be useful to first look at what changed from the proposal the agency first published and the final rules, and why. What motivated the changes, and what, if anything, did they accomplish? What is the significance, for example, of the reduction of building blocks from 4 to 3? Is the impact on the various states different from the original to the final version, and what is the import of that? Going forward, what are the relative strengths and weaknesses of the rules from a substantive point of view (i.e. how effective will it be in cost effective carbon emissions reduction?)? What are the most significant legal vulnerabilities of the rules, and what are the probabilities of success for such challenges? If successful, what remedies are the Courts likely to impose? If upheld by the Courts, what will be the main implementation challenges? How should electricity market participants respond in this new world? Moderator: Lawrence Makovich, HEPG, IHS Bill Scherman, Gibson Dunn Paul Sotkiewicz, PJM Interconnection Michael Wara, Stanford Law School Jürgen Weiss, The Brattle Group 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Adjourn From: To: Subject: Date: Mahoney, Jo-Ann Beth L. Soliere RE: HEPG Agenda and Dinner Invitation Wednesday, September 09, 2015 8:38:55 AM Hi Beth,   Please let Commissioner Stump know that I received his call but unfortunately was called away for a funeral of a close friend of our family.  I know he recommended the Phoenician Hotel.  Can you let me know his other choice?    It would be great for us to connect in NYC but my schedule has me in Massachusetts this week and weekend, as it is the start of the MIT semester.   Please give my best to the commissioner.   Regards, Jo-Ann   From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Tuesday, September 08, 2015 6:29 PM To: Mahoney, Jo-Ann Subject: RE: HEPG Agenda and Dinner Invitation   Hi Jo-Ann,   Commissioner Stump said he tried to call you. You can give him a call or he said that if you will be in NYC this week(end) maybe you guys could meet for coffee.   Thanks,   Beth   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Tuesday, September 01, 2015 11:15 AM To: Beth L. Soliere Subject: RE: HEPG Agenda and Dinner Invitation   Hi Beth,   I am looking for some advice from Commissioner Stump.  We are considering holding our HEPG December meeting in Phoenix and wanted to know if he could recommend some suitable hotel venues, seeing as he is familiar with the HEPG format.  I would need to act on this fairly soon, so an expedient response would be most appreciated.   Thank you,  Jo-Ann     Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu       From: To: Subject: Date: Mahoney, Jo-Ann Beth L. Soliere RE: HEPG Agenda and Dinner Invitation Tuesday, September 01, 2015 11:15:52 AM Hi Beth,   I am looking for some advice from Commissioner Stump.  We are considering holding our HEPG December meeting in Phoenix and wanted to know if he could recommend some suitable hotel venues, seeing as he is familiar with the HEPG format.  I would need to act on this fairly soon, so an expedient response would be most appreciated.   Thank you,  Jo-Ann     Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu       From: To: Subject: Date: Attachments: Beth L. Soliere Bob Stump FW: Registration Open for CCIF 6th Annual Kickoff Forum in Austin on Saturday, Nov. 7, 2015, 2-5 PM Thursday, August 27, 2015 11:33:46 AM CCIF Nov 2015 Kickoff Forum Reg Info.pdf Also- are you going to HEPG?   From: Katrina McMurrian [mailto:katrina@cciforum.com] Sent: Thursday, August 27, 2015 11:25 AM To: katrina@cciforum.com Subject: Registration Open for CCIF 6th Annual Kickoff Forum in Austin on Saturday, Nov. 7, 2015, 2-5 PM   Dear Commissioners – Please see the invitation below (and attached) to the CCIF 6th Annual Kickoff Forum on Saturday afternoon, November 7th, in Austin, at the same hotel as the NARUC & NASUCA Annual Meetings.  Please register for this separate event at the link provided, where you’ll also have the opportunity to indicate interest in a 1-night hotel stipend for participating state commissioners and consumer advocates.  As you make travel plans for Austin, please make hotel and flight arrangements to enable your participation in this Saturday afternoon forum.  We expect a good number of your state commissioner colleagues, commission staff, consumer advocates, electric utility reps, and other stakeholders to join us, and we hope to see you there too!  Katrina (contact info below)   All NARUC & NASUCA Annual Meeting attendees are invited to…   CCIF’s 6th Annual Kickoff Forum Saturday, November 7, 2015 2:00-5:00 pm   JW Marriott Austin, Salon 5   The Critical Consumer Issues Forum (CCIF) invites you to join us in Austin for our 6th Annual Kickoff Forum on an exciting – but yet to be determined – topic in the electric sector. Registration. Registration will open at this link when the NARUC meeting registration opens. Please register by November 2nd. There is no charge to participate, but a separate registration with CCIF is required. Please make travel plans and hotel reservations accordingly. Hotel Accommodations. All registrants are responsible for making their own hotel reservations, including any additional nights to attend the forum. Please be advised that to secure rooms at the JW Marriott Austin at the NARUC conference rate, you must be registered for the NARUC Annual Meeting. Stipends. EEI is offering a limited number of stipends to participating state commissioners and consumer advocates for a 1-night credit at the JW Marriott Austin at the NARUC conference rate (or reimbursement for 1 night at an equal or lower rate at another hotel). Please indicate interest in a stipend during registration, and eligibility will be confirmed soon thereafter. For More Info. Information about CCIF and this forum are posted at www.CCIForum.com. You may also contact Katrina McMurrian, CCIF Executive Director, by e-mail at katrina@CCIForum.com or by phone at 615.905.1375. REGISTER HERE This event is not a part of the agendas of the 127th NARUC Annual Meeting or 2015 NASUCA Annual Meeting. Katrina J. McMurrian Executive Director Critical Consumer Issues Forum (CCIF) 615.905.1375 office 888.526.6883 fax Katrina@CCIForum.com www.CCIForum.com www.Twitter.com/CCIForum All NARUC & NASUCA Annual Meeting attendees are invited to… CCIF’s 6th Annual Kickoff Forum Saturday, November 7, 2015 2:00–5:00 pm JW Marriott Austin Salon 5 The Critical Consumer Issues Forum (CCIF) invites you to join us in Austin for our 6th Annual Kickoff Forum on an exciting – but yet to be determined – topic in the electric sector. Registration. Registration will open at this link when the NARUC meeting registration opens. Please register by November 2nd. There is no charge to participate, but a separate registration with CCIF is required. Please make travel plans and hotel reservations accordingly. Hotel Accommodations. All registrants are responsible for making their own hotel reservations, including any additional nights to attend the forum. Please be advised that to secure rooms at the JW Marriott Austin at the NARUC conference rate, you must be registered for the NARUC Annual Meeting. Stipends. EEI is offering a limited number of stipends to participating state commissioners and consumer advocates for a 1-night credit at the JW Marriott Austin at the NARUC conference rate (or reimbursement for 1 night at an equal or lower rate at another hotel). Please indicate interest in a stipend during registration, and eligibility will be confirmed soon thereafter. For More Info. Information about CCIF and this forum are posted at www.CCIForum.com. You may also contact Katrina McMurrian, CCIF Executive Director, by e-mail at katrina@CCIForum.com or by phone at 615.905.1375. REGISTER HERE This event is not a part of the agendas of the 127th NARUC Annual Meeting or 2015 NASUCA Annual Meeting. CCIF: Engaging state commissioners, consumer advocates, and electric companies to develop mutually agreeable solutions to energy challenges. From: To: Subject: Date: Attachments: Beth L. Soliere Bob Stump FW: HEPG"s October Conference Friday, August 21, 2015 10:53:49 AM Registration Form. Commissioners.docx Want to go?   From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Friday, August 21, 2015 10:29 AM To: Bob Stump Cc: Beth L. Soliere Subject: HEPG's October Conference   Dear Commissioner Stump,   As mentioned in our previous correspondence, the Harvard Electricity Policy Group’s next session will take place in Houston, TX on Thursday and Friday, October 1 and 2, at The Houstonian Hotel. We cordially invite you to attend.   HEPG has reserved a block of rooms at the Houstonian for the evenings of Wednesday, September 30 and Thursday, October 1. I will be happy to make arrangements for your stay. However, please note that the Houstonian has a strict reservation deadline of September 9 and will be unable to accommodate any reservation made after this date. As such, please respond with your completed registration form—attached—and which night(s) you wish to stay at your earliest convenience.   We are pleased to announce the topics for the October meeting: “Computational Frontiers in Electricity Markets: Not Your Grandfather’s Economic Dispatch,” “EPA Clean Power Plan: What Now?,” and “Free Renewables and Electricity Markets: Can Renewables Thrive Through Markets?”  Please find the complete panel descriptions below this email.   As is customary, the session will will convene at breakfast on Thursday, October 1 and adjourn at noon on Friday, October 2. On Thursday evening, we will hold a conference reception and dinner.   Please do not hesitate to contact me if you have any questions or concerns. I look forward to your response and hope you will join us in Houston, TX.   Have a lovely weekend.   Warm regards,   Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu   PANEL DESCRIPTIONS   Computational Frontiers in Electricity Markets:  Not Your Grandfather’s Economic Dispatch The long development of sophisticated software for economic dispatch created a foundational framework for organized electricity markets.  Absent the computational tools, developed well before the era of electricity market reform, the fundamental design found in all organized electricity markets in the United States would have been no more than an ivory tower aspiration.  The early development of markets fully exploited these tools, and their existence disposed of otherwise powerful arguments against open access markets operated under principles of non-discrimination.  Since then, two parallel developments have advanced the capabilities and the need for better computational environments.  First, the software has gotten better, in some cases, much better.  For example, formal optimization for unit commitment was beyond the capability of the early economic dispatch models, but is now available and allows for improvements in market efficiency and market design.   Second, the demand for new market products and expanded markets is increasing rapidly.  For instance, the interest in exploiting distributed resources may fit in the framework of economic dispatch, but at an unprecedented scale compared to the existing wholesale markets for bulk generation.  What are the expanded capabilities of the software?  How does this improvement in software change the scope and reach of electricity markets?  How could and should better software change electricity market design?  What are the limits of the frontier tools?  Are proposals for greatly expanded markets and markets products constrained by unrecognized challenges of big data and big optimization?    EPA Clean Power Plan: What Now? After receiving a huge volume of comments on its proposed rules, EPA issued its Section 111(d) final regulations in the Clean Power Plan.  The agency’s pronouncements are already being critiqued substantively, and challenged both politically and legally.  The final rule setting emission guidelines includes important changes from the proposal.  In looking forward , it would be useful to first look at what changed from the proposal the agency first published and the final rules, and why.  What motivated the changes and what, if anything, did they accomplish?  What is the significance, for example, of the reduction of building blocks from 4 to 3?  Is the impact on the various states different from the original to the final version and what is the import of that?  Going forward: what are the relative strengths and weaknesses of the rules from a substantive point of view (i.e. how effective will it be in cost effective carbon emissions reduction?)? What are the most significant legal vulnerabilities the rules have, and what are the probabilities of success ofare such challenges? If successful, what remedies are the Courts likely to impose?   If upheld by the Courts, what will be the main implementation challenges?  How should electricity market participants respond in this new world?   Free Renewables and Electricity Markets:  Can Renewables Thrive Through Markets? Advocates suggest that we can move fully to an electricity system with only renewable sources of energy. Many counter  that it is virtually impossible because of the intermittent nature of the wind and solar.   Even with a solution for the intermittency problem, however, are there other inherent economic constraints on renewable penetration?   Are free renewables, that have near zero short-run marginal costs, a special case that undermines the electricity market?  Will subsidies be required in perpetuity, particularly if the value of the energy produced decreases faster than the cost as renewable capacity increases?  Does high market penetration of renewables lead inexorably to a declining marginal values, leading to rapid growth of subsidies?  Are the social benefits associated with high penetration of renewables sufficient to justify the subsidies? Are subsidies best provided through mandatory financial arrangements rather than by  a voluntary equilibrium of the market?   Why is electricity market design important?  With high renewables penetration, what are the implications for electricity market design?   REGISTRATION FORM HEPG EIGHTIETH PLENARY SESSION THURSDAY AND FRIDAY, OCTOBER 1-2, 2015 THE HOUSTONIAN HOUSTON, TX TO: HARVARD ELECTRICITY POLICY GROUP John F. Kennedy School of Government FROM: Name Title Affiliation Address Phone E-mail ______YES, I will be able to attend the HEPG Plenary Session. ______ NO, I will not be able to attend the meeting. ______ I would like to send my designee: Name Title Address Phone E-mail ___________________________ ___________________________ ___________________________ ___________________________ ___________________________ ___________________________ HOTEL INFORMATION We have reserved a block of rooms at the Houstonian for the evenings of Wednesday, September 30 and Thursday, October 1. Please arrange your reservation through Hannah Bruner in the Harvard Electricity Policy Group (Hannah_Bruner@hks.harvard.edu) by September 9 at the absolute latest, as the hotel is unable to accommodate any reservations made after this date. The Houstonian is located at 111 North Post Oak Lane, Houston, TX 77024. To register for the session, please fax or e-mail this reply form to: Jo-Ann Mahoney, HEPG Program Director Fax: (617) 495-1635 Email to: Hannah_Bruner@hks.harvard.edu From: To: Cc: Subject: Date: Attachments: Bruner, Hannah Bob Stump Beth L. Soliere HEPG"s October Conference Friday, August 21, 2015 10:29:04 AM Registration Form. Commissioners.docx Dear Commissioner Stump,   As mentioned in our previous correspondence, the Harvard Electricity Policy Group’s next session will take place in Houston, TX on Thursday and Friday, October 1 and 2, at The Houstonian Hotel. We cordially invite you to attend.   HEPG has reserved a block of rooms at the Houstonian for the evenings of Wednesday, September 30 and Thursday, October 1. I will be happy to make arrangements for your stay. However, please note that the Houstonian has a strict reservation deadline of September 9 and will be unable to accommodate any reservation made after this date. As such, please respond with your completed registration form—attached—and which night(s) you wish to stay at your earliest convenience.   We are pleased to announce the topics for the October meeting: “Computational Frontiers in Electricity Markets: Not Your Grandfather’s Economic Dispatch,” “EPA Clean Power Plan: What Now?,” and “Free Renewables and Electricity Markets: Can Renewables Thrive Through Markets?”  Please find the complete panel descriptions below this email.   As is customary, the session will will convene at breakfast on Thursday, October 1 and adjourn at noon on Friday, October 2. On Thursday evening, we will hold a conference reception and dinner.   Please do not hesitate to contact me if you have any questions or concerns. I look forward to your response and hope you will join us in Houston, TX.   Have a lovely weekend.   Warm regards,   Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu   PANEL DESCRIPTIONS   Computational Frontiers in Electricity Markets:  Not Your Grandfather’s Economic Dispatch The long development of sophisticated software for economic dispatch created a foundational framework for organized electricity markets.  Absent the computational tools, developed well before the era of electricity market reform, the fundamental design found in all organized electricity markets in the United States would have been no more than an ivory tower aspiration.  The early development of markets fully exploited these tools, and their existence disposed of otherwise powerful arguments against open access markets operated under principles of non-discrimination.  Since then, two parallel developments have advanced the capabilities and the need for better computational environments.  First, the software has gotten better, in some cases, much better.  For example, formal optimization for unit commitment was beyond the capability of the early economic dispatch models, but is now available and allows for improvements in market efficiency and market design.   Second, the demand for new market products and expanded markets is increasing rapidly.  For instance, the interest in exploiting distributed resources may fit in the framework of economic dispatch, but at an unprecedented scale compared to the existing wholesale markets for bulk generation.  What are the expanded capabilities of the software?  How does this improvement in software change the scope and reach of electricity markets?  How could and should better software change electricity market design?  What are the limits of the frontier tools?  Are proposals for greatly expanded markets and markets products constrained by unrecognized challenges of big data and big optimization?    EPA Clean Power Plan: What Now? After receiving a huge volume of comments on its proposed rules, EPA issued its Section 111(d) final regulations in the Clean Power Plan.  The agency’s pronouncements are already being critiqued substantively, and challenged both politically and legally.  The final rule setting emission guidelines includes important changes from the proposal.  In looking forward , it would be useful to first look at what changed from the proposal the agency first published and the final rules, and why.  What motivated the changes and what, if anything, did they accomplish?  What is the significance, for example, of the reduction of building blocks from 4 to 3?  Is the impact on the various states different from the original to the final version and what is the import of that?  Going forward: what are the relative strengths and weaknesses of the rules from a substantive point of view (i.e. how effective will it be in cost effective carbon emissions reduction?)? What are the most significant legal vulnerabilities the rules have, and what are the probabilities of success ofare such challenges? If successful, what remedies are the Courts likely to impose?   If upheld by the Courts, what will be the main implementation challenges?  How should electricity market participants respond in this new world?   Free Renewables and Electricity Markets:  Can Renewables Thrive Through Markets? Advocates suggest that we can move fully to an electricity system with only renewable sources of energy. Many counter  that it is virtually impossible because of the intermittent nature of the wind and solar.   Even with a solution for the intermittency problem, however, are there other inherent economic constraints on renewable penetration?   Are free renewables, that have near zero short-run marginal costs, a special case that undermines the electricity market?  Will subsidies be required in perpetuity, particularly if the value of the energy produced decreases faster than the cost as renewable capacity increases?  Does high market penetration of renewables lead inexorably to a declining marginal values, leading to rapid growth of subsidies?  Are the social benefits associated with high penetration of renewables sufficient to justify the subsidies? Are subsidies best provided through mandatory financial arrangements rather than by  a voluntary equilibrium of the market?   Why is electricity market design important?  With high renewables penetration, what are the implications for electricity market design?   REGISTRATION FORM HEPG EIGHTIETH PLENARY SESSION THURSDAY AND FRIDAY, OCTOBER 1-2, 2015 THE HOUSTONIAN HOUSTON, TX TO: HARVARD ELECTRICITY POLICY GROUP John F. Kennedy School of Government FROM: Name Title Affiliation Address Phone E-mail ______YES, I will be able to attend the HEPG Plenary Session. ______ NO, I will not be able to attend the meeting. ______ I would like to send my designee: Name Title Address Phone E-mail ___________________________ ___________________________ ___________________________ ___________________________ ___________________________ ___________________________ HOTEL INFORMATION We have reserved a block of rooms at the Houstonian for the evenings of Wednesday, September 30 and Thursday, October 1. Please arrange your reservation through Hannah Bruner in the Harvard Electricity Policy Group (Hannah_Bruner@hks.harvard.edu) by September 9 at the absolute latest, as the hotel is unable to accommodate any reservations made after this date. The Houstonian is located at 111 North Post Oak Lane, Houston, TX 77024. To register for the session, please fax or e-mail this reply form to: Jo-Ann Mahoney, HEPG Program Director Fax: (617) 495-1635 Email to: Hannah_Bruner@hks.harvard.edu From: To: Subject: Date: Bruner, Hannah Beth L. Soliere HEPG"s October Meeting Wednesday, August 12, 2015 10:59:09 AM Dear Ms. Soliere,   On behalf of the Harvard Electricity Policy Group, it is my pleasure to announce that our next meeting will be held in Houston, TX on Thursday and Friday, October 1 and 2.   Further information, including discussion topics and venue, will be distributed early next week.   We would be honored if Commissioner Stump would consider joining us. Please extend our invitation.   Thank you for your time, and have a lovely day.   Best regards,     Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu   From: To: Subject: Date: Bruner, Hannah Beth L. Soliere RE: Travel Reimbursement for HEPG"s 79th Plenary Session in DC Tuesday, July 28, 2015 9:24:29 AM Hi, Beth, Wonderful! Thank you so much. Best, Hannah   From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Tuesday, July 28, 2015 12:23 PM To: Bruner, Hannah Subject: RE: Travel Reimbursement for HEPG's 79th Plenary Session in DC   Hi Hannah!  I actually just had him sign it yesterday. I will send it over shortly.  Thanks for checking. J   From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Tuesday, July 28, 2015 8:04 AM To: Beth L. Soliere Cc: Bob Stump (repbobstump@gmail.com) Subject: RE: Travel Reimbursement for HEPG's 79th Plenary Session in DC   Good morning, Beth, I hope you’re well. I’m just checking-in to ask if I can be of any assistance in completing the reimbursement form for Commissioner Stump. Please let me know if you have any questions or if I can help in any way. Thank you, and have a nice day. Best wishes, Hannah   From: Bruner, Hannah Sent: Tuesday, July 07, 2015 1:28 PM To: Beth L. Soliere (BLSoliere@azcc.gov) Subject: Travel Reimbursement for HEPG's 79th Plenary Session in DC   Good afternoon,   We’re glad Commissioner Stump was able to join us for the HEPG conference in Washington, DC and hope he enjoyed the sessions.   HEPG is happy to reimburse him or the commission for his travel expenses. Please complete and return the attached Non-Employee Reimbursement Form along with the original receipts to my attention at the following address: Hannah Bruner 79 JFK St. Box 84 Cambridge, MA 02138   If you have any questions or concerns, please do not hesitate to contact me.   Best regards,     Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu   From: To: Cc: Subject: Date: Attachments: Bruner, Hannah Beth L. Soliere Bob Stump (repbobstump@gmail.com) RE: Travel Reimbursement for HEPG"s 79th Plenary Session in DC Tuesday, July 28, 2015 8:03:41 AM HCOM_non-employee_reimbursement_form.pdf Good morning, Beth, I hope you’re well. I’m just checking-in to ask if I can be of any assistance in completing the reimbursement form for Commissioner Stump. Please let me know if you have any questions or if I can help in any way. Thank you, and have a nice day. Best wishes, Hannah   From: Bruner, Hannah Sent: Tuesday, July 07, 2015 1:28 PM To: Beth L. Soliere (BLSoliere@azcc.gov) Subject: Travel Reimbursement for HEPG's 79th Plenary Session in DC   Good afternoon,   We’re glad Commissioner Stump was able to join us for the HEPG conference in Washington, DC and hope he enjoyed the sessions.   HEPG is happy to reimburse him or the commission for his travel expenses. Please complete and return the attached Non-Employee Reimbursement Form along with the original receipts to my attention at the following address: Hannah Bruner 79 JFK St. Box 84 Cambridge, MA 02138   If you have any questions or concerns, please do not hesitate to contact me.   Best regards,     Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu   From: To: Date: Beth L. Soliere Bob Stump Wednesday, July 08, 2015 11:06:42 AM Reminder for receipts from HEPG.   Beth Soliere, Executive Aide Commissioner Bob Stump Arizona Corporation Commission 1200 W. Washington Street Phoenix, AZ 85007 602-542-3935   From: To: Subject: Date: Attachments: Bruner, Hannah Beth L. Soliere Travel Reimbursement for HEPG"s 79th Plenary Session in DC Tuesday, July 07, 2015 10:28:04 AM HCOM_non-employee_reimbursement_form.pdf Good afternoon,   We’re glad Commissioner Stump was able to join us for the HEPG conference in Washington, DC and hope he enjoyed the sessions.   HEPG is happy to reimburse him or the commission for his travel expenses. Please complete and return the attached Non-Employee Reimbursement Form along with the original receipts to my attention at the following address: Hannah Bruner 79 JFK St. Box 84 Cambridge, MA 02138   If you have any questions or concerns, please do not hesitate to contact me.   Best regards,     Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu   From: To: Subject: Date: Attachments: Beth L. Soliere Bob Stump FW: HEPG Agenda and Dinner Invitation Friday, June 19, 2015 1:24:41 PM HEPG_6_15_DraftAgenda w Speakers.docx Guest?   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Friday, June 19, 2015 8:53 AM To: Mahoney, Jo-Ann Cc: Bruner, Hannah Subject: HEPG Agenda and Dinner Invitation   We look forward to your participation in our upcoming Harvard Electricity Policy Group Plenary Session to be held in Washington DC next Thursday and Friday, June 25-26.  Our current agenda is attached. The conference will take place at the Mandarin Oriental Hotel.   We will hold the conference reception and dinner at the Decatur Carriage House on Lafayette Square on Thursday, June 25.  The reception will begin at 6:30 pm.  Transportation will be provided from the Mandarin.  You are welcome to bring a guest who is travelling with you.  Kindly RSVP to Hannah Bruner by Tuesday, June 23.   See you in DC, Jo-Ann     Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu     HARVARD ELECTRICITY POLICY GROUP HARVARD ELECTRICITY POLICY GROUP SEVENTY-NINTH PLENARY SESSION Mandarin Oriental Washington, D.C. THURSDAY AND FRIDAY, JUNE 25 - 26, 2015 DRAFT AGENDA Thursday, June 25 8:30 am Breakfast and Informal Discussion 9:00 am Session One. Residential Demand Charges: An Economic Necessity or Political Fatality? Residential demand is in the throes of fundamental change, making it less predictable and more challenging for load serving entities. Contributing to the volatility of demand are a variety of factors, including rooftop solar and other forms of distributed generation, energy efficiency programs, electric vehicles, and storage. There are also new technologies and programs available for customers to control both their demand and consumption. They include smart meters, automated appliance controls, software that enables the queuing of demand, and, of course, time sensitive and dynamic pricing. Given all of these developments, it is no surprise that there are increasing calls for applying demand charges--traditionally applicable only to industrial and commercial load--to residential customers as well. The logic, of course, is simple. There is a fundamental problem. Either there will be a market where prices drive the decisions, or it will be monopoly central procurement. If the former, it is essential that the prices send the correct signals. To send the correct signals, tariffs would have to move to greater demand charges. The traditional arguments against residential demand charges, which have generally prevailed to date--namely that residential customers have less control over demand, that imposition of such charges adds considerable complexity to tariffs for relatively unsophisticated customers, and that, as a result, demand charges would simply increase prices with no fundamental effect on actual demand--still carry political cachet. Is that cachet, plus whatever substantive merit there is to the argument, still potent enough to declare residential demand charges dead on arrival? In recent decisions, the Wisconsin Commission and the elected Board of the Salt River Project in Arizona have decided to impose such charges. Are they anomalies or the harbinger of a changed environment? How are the politics around equity considerations changing? Can we have distributed energy markets without tariff reform? Moderator: Cari Boyce, Duke Energy Barbara Alexander, Consumer Affairs Consultant Ahmed Faruqui, The Brattle Group Meghan Grabel, Arizona Public Service Steve Nadel, American Council for an Energy-Efficient Economy PHONE 617-496-6760 FAX 617-495-1635 EMAIL HEPG@ksg.harvard.edu 79 John F. Kennedy Street, Box 84 Cambridge, Massachusetts 02138 www.hks.harvard.edu/hepg HEPG Draft Agenda, June 25-26, 2015 Thursday, June 25 (cont’d) 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Lunch 1:15 pm Session Two. Hidden Values: Missing Markets and Electricity Policy Incomplete or imperfect markets can produce imperfect reflections of the underlying value of energy services and technologies. The problem is severe enough in the context of working wholesale markets. The issues could become even more significant with the influx of distributed energy resources and greater emphasis on markets in distribution systems. The values may be hidden because of inadequate pricing models (e.g., poor scarcity pricing), missing products (e.g., ancillary services), or fundamental technological implications (e.g., lumpy investment decisions). In some cases, the so-called missing values are really just transfers from one group to another and are more coveted than missing. The policy implications are different depending on the diagnosis. How can we define and estimate the so-called hidden values? Where is the replacement for market discipline to avoid paying for benefits that are less real than imagined? How can markets be changed or pricing reformed to make the values transparent? What are the policy implications for dealing with the hidden values that cannot be made transparent through market redesign? William Hogan, Harvard Kennedy School Hannes Pfeifenberger, The Brattle Group Jeffrey Nelson, Southern California Edison Cheryl Terry, Alberta Electric System Operator 2:45 pm Coffee Break 3:00 pm Discussion 4:15 pm Adjourn 7:00 pm Reception and Dinner HEPG Draft Agenda, June 25-26, 2015 Friday, June 26 8:30 am Breakfast and Informal Discussion 9:00 am Session Three. 80 Years of the Federal Power Act: How Has It Evolved and What Lessons Can We Derive? The Federal Power Act (FPA) turns 80 this year. It has evolved over the years from a Congressional effort to fill a regulatory gap identified by the U.S. Supreme Court in the Attleboro case--namely regulation of interstate commerce in electricity--to a far more comprehensive framework of regulation over wholesale power markets and high voltage transmission. That evolution has both tracked and enabled the changing nature of the power market from vertically integrated utilities to fully competitive bulk power markets and from a closed transmission access regime to an open and dynamic one. The evolution has also been marked by a massive shift of regulatory jurisdiction from the states to the federal government. In the absence of major statutory changes to the law, this evolution has occurred through judicial rulings and through sometimes aggressive federal regulatory actions. Going forward, there are at least two subject areas that are almost certain to impact the FPA. The first is the increasing presence of distributed energy resources in the marketplace. While they have traditionally been seen as an inherent part of retail markets--still largely the domain of state regulators--their effect on the overall market is likely to be such that it may well attract the attention of those responsible for the FPA. The litigation over jurisdiction regarding demand response is not only exemplary of the types of controversies that will emerge, but may, in fact, be the harbinger of what is to come. Another challenge, of course, does not involve state/federal jurisdictional issues, but rather the interface of two schemes of federal regulation: the FPA and the Clean Air Act. The debate over 111(d) and its impact on the power market is illustrative of what may lie ahead. How will the FPA evolve to meet these and other challenges in the future? What lessons can we derive from the 80 years of FPA history that will help us move forward? Moderator: Anne Hoskins, Maryland Public Service Commission Lon Bouknight, Steptoe & Johnson Suedeen Kelly, Akin Gump Strauss Hauer & Feld Cheryl LaFleur, Federal Energy Regulatory Commission Jim Rossi, Vanderbilt University Law School 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Adjourn From: To: Cc: Subject: Date: Attachments: Mahoney, Jo-Ann Mahoney, Jo-Ann Bruner, Hannah HEPG Agenda and Dinner Invitation Friday, June 19, 2015 8:52:51 AM HEPG_6_15_DraftAgenda w Speakers.docx We look forward to your participation in our upcoming Harvard Electricity Policy Group Plenary Session to be held in Washington DC next Thursday and Friday, June 25-26.  Our current agenda is attached. The conference will take place at the Mandarin Oriental Hotel.   We will hold the conference reception and dinner at the Decatur Carriage House on Lafayette Square on Thursday, June 25.  The reception will begin at 6:30 pm.  Transportation will be provided from the Mandarin.  You are welcome to bring a guest who is travelling with you.  Kindly RSVP to Hannah Bruner by Tuesday, June 23.   See you in DC, Jo-Ann     Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu     HARVARD ELECTRICITY POLICY GROUP HARVARD ELECTRICITY POLICY GROUP SEVENTY-NINTH PLENARY SESSION Mandarin Oriental Washington, D.C. THURSDAY AND FRIDAY, JUNE 25 - 26, 2015 DRAFT AGENDA Thursday, June 25 8:30 am Breakfast and Informal Discussion 9:00 am Session One. Residential Demand Charges: An Economic Necessity or Political Fatality? Residential demand is in the throes of fundamental change, making it less predictable and more challenging for load serving entities. Contributing to the volatility of demand are a variety of factors, including rooftop solar and other forms of distributed generation, energy efficiency programs, electric vehicles, and storage. There are also new technologies and programs available for customers to control both their demand and consumption. They include smart meters, automated appliance controls, software that enables the queuing of demand, and, of course, time sensitive and dynamic pricing. Given all of these developments, it is no surprise that there are increasing calls for applying demand charges--traditionally applicable only to industrial and commercial load--to residential customers as well. The logic, of course, is simple. There is a fundamental problem. Either there will be a market where prices drive the decisions, or it will be monopoly central procurement. If the former, it is essential that the prices send the correct signals. To send the correct signals, tariffs would have to move to greater demand charges. The traditional arguments against residential demand charges, which have generally prevailed to date--namely that residential customers have less control over demand, that imposition of such charges adds considerable complexity to tariffs for relatively unsophisticated customers, and that, as a result, demand charges would simply increase prices with no fundamental effect on actual demand--still carry political cachet. Is that cachet, plus whatever substantive merit there is to the argument, still potent enough to declare residential demand charges dead on arrival? In recent decisions, the Wisconsin Commission and the elected Board of the Salt River Project in Arizona have decided to impose such charges. Are they anomalies or the harbinger of a changed environment? How are the politics around equity considerations changing? Can we have distributed energy markets without tariff reform? Moderator: Cari Boyce, Duke Energy Barbara Alexander, Consumer Affairs Consultant Ahmed Faruqui, The Brattle Group Meghan Grabel, Arizona Public Service Steve Nadel, American Council for an Energy-Efficient Economy PHONE 617-496-6760 FAX 617-495-1635 EMAIL HEPG@ksg.harvard.edu 79 John F. Kennedy Street, Box 84 Cambridge, Massachusetts 02138 www.hks.harvard.edu/hepg HEPG Draft Agenda, June 25-26, 2015 Thursday, June 25 (cont’d) 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Lunch 1:15 pm Session Two. Hidden Values: Missing Markets and Electricity Policy Incomplete or imperfect markets can produce imperfect reflections of the underlying value of energy services and technologies. The problem is severe enough in the context of working wholesale markets. The issues could become even more significant with the influx of distributed energy resources and greater emphasis on markets in distribution systems. The values may be hidden because of inadequate pricing models (e.g., poor scarcity pricing), missing products (e.g., ancillary services), or fundamental technological implications (e.g., lumpy investment decisions). In some cases, the so-called missing values are really just transfers from one group to another and are more coveted than missing. The policy implications are different depending on the diagnosis. How can we define and estimate the so-called hidden values? Where is the replacement for market discipline to avoid paying for benefits that are less real than imagined? How can markets be changed or pricing reformed to make the values transparent? What are the policy implications for dealing with the hidden values that cannot be made transparent through market redesign? William Hogan, Harvard Kennedy School Hannes Pfeifenberger, The Brattle Group Jeffrey Nelson, Southern California Edison Cheryl Terry, Alberta Electric System Operator 2:45 pm Coffee Break 3:00 pm Discussion 4:15 pm Adjourn 7:00 pm Reception and Dinner HEPG Draft Agenda, June 25-26, 2015 Friday, June 26 8:30 am Breakfast and Informal Discussion 9:00 am Session Three. 80 Years of the Federal Power Act: How Has It Evolved and What Lessons Can We Derive? The Federal Power Act (FPA) turns 80 this year. It has evolved over the years from a Congressional effort to fill a regulatory gap identified by the U.S. Supreme Court in the Attleboro case--namely regulation of interstate commerce in electricity--to a far more comprehensive framework of regulation over wholesale power markets and high voltage transmission. That evolution has both tracked and enabled the changing nature of the power market from vertically integrated utilities to fully competitive bulk power markets and from a closed transmission access regime to an open and dynamic one. The evolution has also been marked by a massive shift of regulatory jurisdiction from the states to the federal government. In the absence of major statutory changes to the law, this evolution has occurred through judicial rulings and through sometimes aggressive federal regulatory actions. Going forward, there are at least two subject areas that are almost certain to impact the FPA. The first is the increasing presence of distributed energy resources in the marketplace. While they have traditionally been seen as an inherent part of retail markets--still largely the domain of state regulators--their effect on the overall market is likely to be such that it may well attract the attention of those responsible for the FPA. The litigation over jurisdiction regarding demand response is not only exemplary of the types of controversies that will emerge, but may, in fact, be the harbinger of what is to come. Another challenge, of course, does not involve state/federal jurisdictional issues, but rather the interface of two schemes of federal regulation: the FPA and the Clean Air Act. The debate over 111(d) and its impact on the power market is illustrative of what may lie ahead. How will the FPA evolve to meet these and other challenges in the future? What lessons can we derive from the 80 years of FPA history that will help us move forward? Moderator: Anne Hoskins, Maryland Public Service Commission Lon Bouknight, Steptoe & Johnson Suedeen Kelly, Akin Gump Strauss Hauer & Feld Cheryl LaFleur, Federal Energy Regulatory Commission Jim Rossi, Vanderbilt University Law School 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Adjourn From: To: Subject: Date: Attachments: Bruner, Hannah Beth L. Soliere Confirmation Number / Agenda Thursday, June 18, 2015 9:17:49 AM HEPG_6_15_DraftAgenda w Speakers.docx Good morning, Beth, I can’t remember if I sent you the Commissioner’s hotel confirmation number or not. It is 47M1WY. Check-in is 3:00 pm on Wednesday, June 24, and check-out is 12:00 pm on Friday, June 26. I am also attaching the most recent version of the Draft Agenda. Best wishes,     Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu   HARVARD ELECTRICITY POLICY GROUP HARVARD ELECTRICITY POLICY GROUP SEVENTY-NINTH PLENARY SESSION Mandarin Oriental Washington, D.C. THURSDAY AND FRIDAY, JUNE 25 - 26, 2015 DRAFT AGENDA Thursday, June 25 8:30 am Breakfast and Informal Discussion 9:00 am Session One. Residential Demand Charges: An Economic Necessity or Political Fatality? Residential demand is in the throes of fundamental change, making it less predictable and more challenging for load serving entities. Contributing to the volatility of demand are a variety of factors, including rooftop solar and other forms of distributed generation, energy efficiency programs, electric vehicles, and storage. There are also new technologies and programs available for customers to control both their demand and consumption. They include smart meters, automated appliance controls, software that enables the queuing of demand, and, of course, time sensitive and dynamic pricing. Given all of these developments, it is no surprise that there are increasing calls for applying demand charges--traditionally applicable only to industrial and commercial load--to residential customers as well. The logic, of course, is simple. There is a fundamental problem. Either there will be a market where prices drive the decisions, or it will be monopoly central procurement. If the former, it is essential that the prices send the correct signals. To send the correct signals, tariffs would have to move to greater demand charges. The traditional arguments against residential demand charges, which have generally prevailed to date--namely that residential customers have less control over demand, that imposition of such charges adds considerable complexity to tariffs for relatively unsophisticated customers, and that, as a result, demand charges would simply increase prices with no fundamental effect on actual demand--still carry political cachet. Is that cachet, plus whatever substantive merit there is to the argument, still potent enough to declare residential demand charges dead on arrival? In recent decisions, the Wisconsin Commission and the elected Board of the Salt River Project in Arizona have decided to impose such charges. Are they anomalies or the harbinger of a changed environment? How are the politics around equity considerations changing? Can we have distributed energy markets without tariff reform? Moderator: Cari Boyce, Duke Energy Barbara Alexander, Consumer Affairs Consultant Ahmed Faruqui, The Brattle Group Meghan Grabel, Arizona Public Service Steve Nadel, American Council for an Energy-Efficient Economy PHONE 617-496-6760 FAX 617-495-1635 EMAIL HEPG@ksg.harvard.edu 79 John F. Kennedy Street, Box 84 Cambridge, Massachusetts 02138 www.hks.harvard.edu/hepg HEPG Draft Agenda, June 25-26, 2015 Thursday, June 25 (cont’d) 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Lunch 1:15 pm Session Two. Hidden Values: Missing Markets and Electricity Policy Incomplete or imperfect markets can produce imperfect reflections of the underlying value of energy services and technologies. The problem is severe enough in the context of working wholesale markets. The issues could become even more significant with the influx of distributed energy resources and greater emphasis on markets in distribution systems. The values may be hidden because of inadequate pricing models (e.g., poor scarcity pricing), missing products (e.g., ancillary services), or fundamental technological implications (e.g., lumpy investment decisions). In some cases, the so-called missing values are really just transfers from one group to another and are more coveted than missing. The policy implications are different depending on the diagnosis. How can we define and estimate the so-called hidden values? Where is the replacement for market discipline to avoid paying for benefits that are less real than imagined? How can markets be changed or pricing reformed to make the values transparent? What are the policy implications for dealing with the hidden values that cannot be made transparent through market redesign? William Hogan, Harvard Kennedy School Hannes Pfeifenberger, The Brattle Group Jeffrey Nelson, Southern California Edison Cheryl Terry, Alberta Electric System Operator 2:45 pm Coffee Break 3:00 pm Discussion 4:15 pm Adjourn 7:00 pm Reception and Dinner HEPG Draft Agenda, June 25-26, 2015 Friday, June 26 8:30 am Breakfast and Informal Discussion 9:00 am Session Three. 80 Years of the Federal Power Act: How Has It Evolved and What Lessons Can We Derive? The Federal Power Act (FPA) turns 80 this year. It has evolved over the years from a Congressional effort to fill a regulatory gap identified by the U.S. Supreme Court in the Attleboro case--namely regulation of interstate commerce in electricity--to a far more comprehensive framework of regulation over wholesale power markets and high voltage transmission. That evolution has both tracked and enabled the changing nature of the power market from vertically integrated utilities to fully competitive bulk power markets and from a closed transmission access regime to an open and dynamic one. The evolution has also been marked by a massive shift of regulatory jurisdiction from the states to the federal government. In the absence of major statutory changes to the law, this evolution has occurred through judicial rulings and through sometimes aggressive federal regulatory actions. Going forward, there are at least two subject areas that are almost certain to impact the FPA. The first is the increasing presence of distributed energy resources in the marketplace. While they have traditionally been seen as an inherent part of retail markets--still largely the domain of state regulators--their effect on the overall market is likely to be such that it may well attract the attention of those responsible for the FPA. The litigation over jurisdiction regarding demand response is not only exemplary of the types of controversies that will emerge, but may, in fact, be the harbinger of what is to come. Another challenge, of course, does not involve state/federal jurisdictional issues, but rather the interface of two schemes of federal regulation: the FPA and the Clean Air Act. The debate over 111(d) and its impact on the power market is illustrative of what may lie ahead. How will the FPA evolve to meet these and other challenges in the future? What lessons can we derive from the 80 years of FPA history that will help us move forward? Moderator: Anne Hoskins, Maryland Public Service Commission Lon Bouknight, Steptoe & Johnson Suedeen Kelly, Akin Gump Strauss Hauer & Feld Cheryl LaFleur, Federal Energy Regulatory Commission Jim Rossi, Vanderbilt University Law School Jody Freeman, Harvard Law School (Tentative) 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Adjourn From: To: Subject: Date: Bostian, Trudi Beth L. Soliere RE: Wednesday, June 10, 2015 10:41:57 AM No problem – please give the Chairman my best!    ************************************    Trudi Bostian Faculty Staff Assistant Evidence for Policy Design Harvard Kennedy School 79 John F. Kennedy Street, Mailbox 46 Cambridge, MA 02138 Ph: 617-495-9965 E: trudi_bostian@hks.harvard.edu   From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Wednesday, June 10, 2015 11:56 AM To: Bostian, Trudi Subject: RE:   I’m sorry, Trudi. I knew that, I meant to send this to Jo-Ann.   Thank you though!  J   From: Bostian, Trudi [mailto:Trudi_Bostian@hks.harvard.edu] Sent: Wednesday, June 10, 2015 5:46 AM To: Beth L. Soliere; Mahoney, Jo-Ann; Bruner, Hannah Subject: RE:   Dear Beth,   I no longer work with HEPG, unfortunately, so I am forwarding your message to those who can answer that question for you.   Thanks so much.   ************************************    Trudi Bostian Faculty Staff Assistant Evidence for Policy Design Harvard Kennedy School 79 John F. Kennedy Street, Mailbox 46 Cambridge, MA 02138 Ph: 617-495-9965 E: trudi_bostian@hks.harvard.edu   From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Tuesday, June 09, 2015 2:53 PM To: Bostian, Trudi Subject:   Hi Trudi,   I just want to make sure that Commissioner Stump is all signed up for the June meeting with a room for the 24th and 25th.   Thanks,     Beth Soliere, Executive Aide Commissioner Bob Stump Arizona Corporation Commission 1200 W. Washington Street Phoenix, AZ 85007 602-542-3935   From: To: Subject: Date: Attachments: Bruner, Hannah Beth L. Soliere RE: Wednesday, June 10, 2015 6:46:42 AM HEPG_6_15_DraftAgenda.docx Good morning, Beth, Commissioner Stump is registered. His hotel confirmation number is 47M1WY. Also, please find attached the draft agenda. Best wishes, Hannah   From: Bostian, Trudi Sent: Wednesday, June 10, 2015 8:46 AM To: Beth L. Soliere; Mahoney, Jo-Ann; Bruner, Hannah Subject: RE:   Dear Beth,   I no longer work with HEPG, unfortunately, so I am forwarding your message to those who can answer that question for you.   Thanks so much.   ************************************    Trudi Bostian Faculty Staff Assistant Evidence for Policy Design Harvard Kennedy School 79 John F. Kennedy Street, Mailbox 46 Cambridge, MA 02138 Ph: 617-495-9965 E: trudi_bostian@hks.harvard.edu   From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Tuesday, June 09, 2015 2:53 PM To: Bostian, Trudi Subject:   Hi Trudi,   I just want to make sure that Commissioner Stump is all signed up for the June meeting with a room for the 24th and 25th.   Thanks,     Beth Soliere, Executive Aide Commissioner Bob Stump Arizona Corporation Commission 1200 W. Washington Street Phoenix, AZ 85007 602?542?3935 HARVARD ELECTRICITY POLICY GROUP HARVARD ELECTRICITY POLICY GROUP SEVENTY-NINTH PLENARY SESSION Mandarin Oriental Washington, D.C. THURSDAY AND FRIDAY, JUNE 25 - 26, 2015 DRAFT AGENDA Thursday, June 25 8:30 am Breakfast and Informal Discussion 9:00 am Session One. Residential Demand Charges: An Economic Necessity or Political Fatality? Residential demand is in the throes of fundamental change, making it less predictable and more challenging for load serving entities. Contributing to the volatility of demand are a variety of factors, including rooftop solar and other forms of distributed generation, energy efficiency programs, electric vehicles, and storage. There are also new technologies and programs available for customers to control both their demand and consumption. They include smart meters, automated appliance controls, software that enables the queuing of demand, and, of course, time sensitive and dynamic pricing. Given all of these developments, it is no surprise that there are increasing calls for applying demand charges--traditionally applicable only to industrial and commercial load--to residential customers as well. The logic, of course, is simple. There is a fundamental problem. Either there will be a market where prices drive the decisions, or it will be monopoly central procurement. If the former, it is essential that the prices send the correct signals. To send the correct signals, tariffs would have to move to greater demand charges. The traditional arguments against residential demand charges, which have generally prevailed to date--namely that residential customers have less control over demand, that imposition of such charges adds considerable complexity to tariffs for relatively unsophisticated customers, and that, as a result, demand charges would simply increase prices with no fundamental effect on actual demand--still carry political cachet. Is that cachet, plus whatever substantive merit there is to the argument, still potent enough to declare residential demand charges dead on arrival? In recent decisions, the Wisconsin Commission and the elected Board of the Salt River Project in Arizona have decided to impose such charges. Are they anomalies or the harbinger of a changed environment? How are the politics around equity considerations changing? Can we have distributed energy markets without tariff reform? PHONE 617-496-6760 FAX 617-495-1635 EMAIL HEPG@ksg.harvard.edu 79 John F. Kennedy Street, Box 84 Cambridge, Massachusetts 02138 www.hks.harvard.edu/hepg HEPG Draft Agenda, June 25-26, 2015 Thursday, June 25 (cont’d) 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Lunch 1:15 pm Session Two. Hidden Values: Missing Markets and Electricity Policy Incomplete or imperfect markets can produce imperfect reflections of the underlying value of energy services and technologies. The problem is severe enough in the context of working wholesale markets. The issues could become even more significant with the influx of distributed energy resources and greater emphasis on markets in distribution systems. The values may be hidden because of inadequate pricing models (e.g., poor scarcity pricing), missing products (e.g., ancillary services), or fundamental technological implications (e.g., lumpy investment decisions). In some cases, the so-called missing values are really just transfers from one group to another and are more coveted than missing. The policy implications are different depending on the diagnosis. How can we define and estimate the so-called hidden values? Where is the replacement for market discipline to avoid paying for benefits that are less real than imagined? How can markets be changed or pricing reformed to make the values transparent? What are the policy implications for dealing with the hidden values that cannot be made transparent through market redesign? 2:45 pm Coffee Break 3:00 pm Discussion 4:15 pm Adjourn 7:00 pm Reception and Dinner HEPG Draft Agenda, June 25-26, 2015 Friday, June 26 8:30 am Breakfast and Informal Discussion 9:00 am Session Three. 80 Years of the Federal Power Act: How Has It Evolved and What Lessons Can We Derive? The Federal Power Act (FPA) turns 80 this year. It has evolved over the years from a Congressional effort to fill a regulatory gap identified by the U.S. Supreme Court in the Attleboro case--namely regulation of interstate commerce in electricity--to a far more comprehensive framework of regulation over wholesale power markets and high voltage transmission. That evolution has both tracked and enabled the changing nature of the power market from vertically integrated utilities to fully competitive bulk power markets and from a closed transmission access regime to an open and dynamic one. The evolution has also been marked by a massive shift of regulatory jurisdiction from the states to the federal government. In the absence of major statutory changes to the law, this evolution has occurred through judicial rulings and through sometimes aggressive federal regulatory actions. Going forward, there are at least two subject areas that are almost certain to impact the FPA. The first is the increasing presence of distributed energy resources in the marketplace. While they have traditionally been seen as an inherent part of retail markets--still largely the domain of state regulators--their effect on the overall market is likely to be such that it may well attract the attention of those responsible for the FPA. The litigation over jurisdiction regarding demand response is not only exemplary of the types of controversies that will emerge, but may, in fact, be the harbinger of what is to come. Another challenge, of course, does not involve state/federal jurisdictional issues, but rather the interface of two schemes of federal regulation: the FPA and the Clean Air Act. The debate over 111(d) and its impact on the power market is illustrative of what may lie ahead. How will the FPA evolve to meet these and other challenges in the future? What lessons can we derive from the 80 years of FPA history that will help us move forward? 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Adjourn From: To: Subject: Date: Bostian, Trudi Beth L. Soliere; Mahoney, Jo-Ann; Bruner, Hannah RE: Wednesday, June 10, 2015 5:45:00 AM Dear Beth,   I no longer work with HEPG, unfortunately, so I am forwarding your message to those who can answer that question for you.   Thanks so much.   ************************************    Trudi Bostian Faculty Staff Assistant Evidence for Policy Design Harvard Kennedy School 79 John F. Kennedy Street, Mailbox 46 Cambridge, MA 02138 Ph: 617-495-9965 E: trudi_bostian@hks.harvard.edu   From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Tuesday, June 09, 2015 2:53 PM To: Bostian, Trudi Subject:   Hi Trudi,   I just want to make sure that Commissioner Stump is all signed up for the June meeting with a room for the 24th and 25th.   Thanks,     Beth Soliere, Executive Aide Commissioner Bob Stump Arizona Corporation Commission 1200 W. Washington Street Phoenix, AZ 85007 602-542-3935   From: To: Subject: Date: Beth L. Soliere Bob Stump RE: HEPG June 24th and 25th Tuesday, June 09, 2015 3:01:18 PM Yep, you will just need to fly out on the 24th.  It starts on the 25th.   From: Bob Stump Sent: Tuesday, June 09, 2015 3:02 PM To: Beth L. Soliere Subject: Re: HEPG June 24th and 25th   Thought I asked this today. But can't find the thread. This is actually 25th and ending noon on the 26th, right? NOT the 24th.  Sent from my iPhone On Jun 4, 2015, at 3:46 PM, Beth L. Soliere wrote: You also need to get your flight for this.   Beth Soliere, Executive Aide Commissioner Bob Stump Arizona Corporation Commission 1200 W. Washington Street Phoenix, AZ 85007 602-542-3935   From: To: Subject: Date: Bob Stump Beth L. Soliere HEPG Tuesday, June 09, 2015 11:45:34 AM Starts the morning of the 25th and ends at noon on the 26th? Two nights covered, I assume. I Need to get the ticket today. Sent from my iPhone From: To: Subject: Date: Attachments: Bruner, Hannah Beth L. Soliere Invitation to Attend HEPG"s 79th Plenary Session Friday, May 08, 2015 8:49:04 AM Commissioner Registration_form_6.15.docx Dear Beth,   On behalf of the Harvard Electricity Policy Group, it is my pleasure to invite Commissioner Stump to attend the Seventy-Ninth Plenary Session of the Harvard Electricity Policy Group. This session will be held at the Mandarin Oriental in Washington, D.C. on the dates of Thursday, June 25 and Friday, June 26, 2015.   As we are currently planning discussion topics, we will announce those in the coming weeks. We appreciate your patience in this matter.   HEPG will reimburse travel expenses, within reason, and can arrange a room at the Mandarin Oriental for Wednesday, June 24 and Thursday, June 25. Please advise me of which of these nights the Commissioner will be staying.   Kindly return completed the attached registration form to Hannah_Bruner@hks.harvard.edu.   We sincerely hope he will join us in Washington.   Thank you, and have a lovely weekend.   Warm regards,       Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu   REGISTRATION FORM HEPG SEVENTY-NINTH PLENARY SESSION THURSDAY AND FRIDAY, JUNE 25-26, 2015 MANDARIN ORIENTAL WASHINGTON, D.C. TO: HARVARD ELECTRICITY POLICY GROUP John F. Kennedy School of Government FROM: Name Title Affiliation Address Phone E-mail ______YES, I will be able to attend the HEPG Plenary Session. ______ NO, I will not be able to attend the meeting. ______ I would like to send my designee: Name Title Address Phone E-mail ___________________________ ___________________________ ___________________________ ___________________________ ___________________________ ___________________________ HOTEL INFORMATION We have reserved a block of rooms at the Mandarin Oriental Washington D.C. for the evenings of Wednesday, June 24 and Thursday, June 25. Please arrange your reservation through Hannah Bruner in the Harvard Electricity Policy Group: Hannah_Bruner@hks.harvard.edu. The Mandarin Oriental is located at 1330 Maryland Avenue SW, Washington, D.C. 20024. To register for the session, please fax or e-mail this reply form to: Jo-Ann Mahoney, HEPG Program Director Fax: (617) 495-1635 Phone: (617) 495-1390 email to: jo-ann_mahoney@harvard.edu and cc: Hannah_Bruner@hks.harvard.edu From: To: Subject: Date: Bruner, Hannah Beth L. Soliere Received Forms/Original Receipts Wednesday, May 06, 2015 6:45:31 AM Good morning, Beth, I just wanted to send you a quick message letting you know I received the financial forms and receipts you sent in the mail this morning. Thank you for sending them. They will be send in for processing momentarily. On another note, I will be sending out invitations to the next HEPG meeting this afternoon. I hope you have a great day! Best,   Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu   From: To: Subject: Date: Beth L. Soliere Bob Stump RE: 6/25 Ted Craver meeting with Commissioner Stump Friday, April 17, 2015 9:38:45 AM Ok she said that the morning of the 24th will work. How early? Also- she asked for recommendations for a hotel near our office. I was thinking Sheraton, Hyatt, Renaissance…what do you think?   From: Bob Stump Sent: Thursday, April 16, 2015 2:45 PM To: Beth L. Soliere Subject: Re: 6/25 Ted Craver meeting with Commissioner Stump   Darn it. How about as early as possible on the 24th? Could you double check with Hannah as to the dates and the time it begins? Thanks.  Sent from my iPhone On Apr 16, 2015, at 2:47 PM, Beth L. Soliere wrote: It looks like HEPG is happening on the 25th of June- you are planning to attend right? I could ask them to do the 24th.   From: Katherine Wong Exec Asst [mailto:Katherine.Wong@edisonintl.com] Sent: Thursday, April 16, 2015 1:14 PM To: Beth L. Soliere Subject: 6/25 Ted Craver meeting with Commissioner Stump   Hi Beth:   I would like to confirm Thursday, June 25. Does the Commissioner have a time preference for the meeting? Will the meeting take place in the Washington Street office?   Thanks. Kathy Katherine Wong Executive Assistant to Ted Craver Chairman & CEO Edison International *********************************************************** 2244 Walnut Grove Avenue Rosemead, CA 91770 GO1, Room 428 Direct 626-302-2288 Fax 626-302-2210 katherine.wong@edisonintl.com P Please consider the cost and environment before printing this email. ***NOTICE*** This e-mail message is confidential, is intended only for the named recipient(s) above, and may contain information that is privileged, attorney work product or exempt from disclosure under applicable law. If you have received this message in error, or are not a named recipient(s), you are hereby notified that any dissemination, distribution or copying of this e-mail is strictly prohibited. If you have received this message in error, please immediately notify the sender by return email and delete this email message from your computer. Thank you.   From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Thursday, April 09, 2015 9:34 AM To: Katherine Wong Exec Asst Subject: RE: Request for meeting with Commissioner Stump   Hi Katherine,   Either day is great for us. Just let me know.   Thank you,     Beth Soliere, Executive Aide Commissioner Bob Stump Arizona Corporation Commission 1200 W. Washington Street Phoenix, AZ 85007 602-542-3935       From: Katherine Wong Exec Asst [mailto:Katherine.Wong@edisonintl.com] Sent: Thursday, April 09, 2015 8:32 AM To: Beth L. Soliere Subject: RE: Request for meeting with Commissioner Stump   Hi Beth, just resending in case your didn’t see my last email. Thanks. Kathy Direct 626-302-2288   From: Katherine Wong Exec Asst Sent: Tuesday, April 07, 2015 10:03 AM To: 'blsoliere@azcc.gov' Subject: Request for meeting with Commissioner Stump   Hi Beth:   Ted Craver and Commissioner Stump were co-panelists at Powering the People on March 19. They spoke about getting together. Ted will likely be traveling to Pheonix on June 24 or 25. Please let me know if the Commissioner may have time to meet with Ted. Thanks. Kathy Katherine Wong Executive Assistant to Ted Craver Chairman & CEO Edison International *********************************************************** 2244 Walnut Grove Avenue Rosemead, CA 91770 GO1, Room 428 Direct 626-302-2288 Fax 626-302-2210 katherine.wong@edisonintl.com P Please consider the cost and environment before printing this email. ***NOTICE*** This e-mail message is confidential, is intended only for the named recipient(s) above, and may contain information that is privileged, attorney work product or exempt from disclosure under applicable law. If you have received this message in error, or are not a named recipient(s), you are hereby notified that any dissemination, distribution or copying of this e-mail is strictly prohibited. If you have received this message in error, please immediately notify the sender by return email and delete this email message from your computer. Thank you.   From: To: Subject: Date: Bruner, Hannah Beth L. Soliere RE: Friday, April 17, 2015 6:37:58 AM Hi, Beth, Sure. The next meeting is in D.C. on June 25-6. Happy Friday! Best, Hannah   From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Thursday, April 16, 2015 6:05 PM To: Bruner, Hannah Subject:   Hi Hannah,   Can you tell me when the next HEPG meeting is?   Thanks,   Beth Soliere, Executive Aide Commissioner Bob Stump Arizona Corporation Commission 1200 W. Washington Street Phoenix, AZ 85007 602-542-3935   From: To: Subject: Date: Teresa Tenbrink Beth L. Soliere RE: Thursday, April 16, 2015 2:42:16 PM Yep in D.C. No details yet.   Teresa Tenbrink Executive Aide to Chairman Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   Please join us for the Western Conference of Public Service Commissioners! http://western.naruc.org/meetings.cfm     From: Beth L. Soliere Sent: Thursday, April 16, 2015 2:41 PM To: Teresa Tenbrink Subject:   Is HEPG happening again June 25th?   Beth Soliere, Executive Aide Commissioner Bob Stump Arizona Corporation Commission 1200 W. Washington Street Phoenix, AZ 85007 602-542-3935   From: To: Subject: Date: Beth L. Soliere Bob Stump receipts Thursday, April 16, 2015 11:40:55 AM We need to get the receipts in for HEPG and IEI. Did you look at them yet?   Are the AP email ok to give back to legal?   Beth Soliere, Executive Aide Commissioner Bob Stump Arizona Corporation Commission 1200 W. Washington Street Phoenix, AZ 85007 602-542-3935   From: To: Subject: Date: Attachments: Bruner, Hannah Beth L. Soliere RE: Reimbursement for last week"s HEPG session Tuesday, April 14, 2015 6:26:32 AM non-employee reimbursement.pdf Hi, Beth, Please use the attached form instead. Let me know if you have trouble opening it. Thank you! Best, Hannah   From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Monday, April 13, 2015 6:09 PM To: Bruner, Hannah Subject: FW: Reimbursement for last week's HEPG session   I found this one. I can use this if it is the same. I am able to open this one.   From: Bostian, Trudi [mailto:Trudi_Bostian@hks.harvard.edu] Sent: Tuesday, June 17, 2014 8:16 AM To: kenneth.anderson@puc.texas.gov; Monica.Lambert@puc.texas.gov; Rich.Wakeland@puc.texas.gov; Susan Bitter Smith; Teresa Tenbrink; jcolgan@icc.illinois.gov; cweller@icc.illinois.gov; jeanne.fox@bpu.state.nj.us; deborah.laird@bpu.state.nj.us; r.csira@bpu.state.nj.us; neil.jamieson@auc.ab.ca; pjones@wutc.wa.gov; dholman@utc.wa.gov; tkavulla@mt.gov; amccabe@icc.illinois.gov; cweller@icc.illinois.gov; donna.nelson@puc.texas.gov; Lisa.Cantu@puc.texas.gov; catherine.sandoval@cpuc.ca.gov; annchristina.rothchild@cpuc.ca.gov; Bob Stump; Beth L. Soliere Subject: Reimbursement for last week's HEPG session   Hello,   It was wonderful to see all of you in Cambridge last week, and I hope you benefited from the conference and the discussions.   In order to receive reimbursement for your travel expenses, I will need you to follow these steps.   If Harvard is reimbursing you personally: Please fill out the attached Universal Expense Form and send this to me, along with original copies of your receipts. If you do not have receipts, or if you prefer to send scans via email, please also fill out the attached missing receipt affidavit.   If Harvard is reimbursing your organization: Please submit an invoice, on official letterhead, outlining the specific charges incurred and preferred method of payment.  Please also send me original receipts, and include a signed missing receipt affidavit if you use scans or if any receipts are missing.   Let me know if you have any questions or concerns.    ******************************* Trudi R. Bostian Staff Assistant Harvard Electricity Policy Group 79 John F. Kennedy Street Cambridge, MA 02138 P: 617-496-6760 E: trudi_bostian@hks.harvard.edu   Ellil?l?l Il??wmizm?h,? . Harvard University on Em ployee Relm bu rsement Form University Financial Services - 1033 Massachusetts Ave, 2nd Floor Cambridge, MA 02138 Request Date: NR Number*: Reimbursee Name: Requisition Affiliation 0 Invited Guest Harvard Student OOther (Explain below) HUID (Affiliates):* Other Explanation US. Citizen orPermanent Resident QYes ONO FederaISponored Funds ?CiYes ONO Dates of Business Purpose: Provide detailed reasons and date ranges for expenditures. Travel and entertainment Expense(5) expenses require the person(s) and/or organization and location. ALL expenses must be itemized. #1 #2 #3 ALL EXPENSES MUST BE ITEMIZED INCLUDING EXPENSES LESS THAN $75 (A DETAILED ITEMIZED LIST FOR EXPENSES LESS THAN $75 CAN BE ATTACHED To THIS FORM) Description (date, details, etc) Air/Rail Lodging Bub/11229555 Other Total #1 #2 #3 Sub-Total expenses from page 2 Total Reimbursement rh Total amount under $75 itemized in Total Reimbursement I certify these are valid business expenses on behalf of Harvard University Reimbursee Signature:* Reimbursee Check Mailing Address:* Prepared By (Print): Phone You agree no unallowable costs, including undocumented expenses under $75, are being charged to Federal Funds as specified in 0MB Circulars A-21 and A-22. Approved By (Print): Phone TO EXPEDITE PAYMENT, PLEASE RETURN COMPLETED FORM AND REQUIRED DOCUMENTATION TO THE UNIT RESPONSIBLE FOR . . PROCESSING THE ELECTRONIC REQUEST *Requlred Field Elli Page 2 terms? Non Employee Relmbursement Form Reimbursee Name: Req?JiSition Additional Expenses Description (date details etc) Air/Rail Lodging Ground Business Other Total Trans Meals Sub-Total Reimbursement Line Distribution Business Purpose Amount Tub Org Object Fund Activity Sub Root *Required Field HINTS AND POLICY NOTES: Please refer to for complete policy. This completed form and required documentation must be returned to the local unit for processing. It? From: To: Subject: Date: Beth L. Soliere Bob Stump HEPG San Fran Wednesday, April 08, 2015 11:48:44 AM Flight- $285.20 Hotel- they reserved and paid Taxi- $120 from airport to hotel Same going back? Need copy of receipt Meals- They provided you with B, L and D on the 24th and B on the 25th. Is that right?  So we would request: D on the 23rd and Lunch on the 25th from the ACC.   Beth Soliere, Executive Aide Commissioner Bob Stump Arizona Corporation Commission 1200 W. Washington Street Phoenix, AZ 85007 602-542-3935   From: To: Subject: Date: Attachments: Bruner, Hannah Beth L. Soliere RE: RE: Wednesday, April 08, 2015 11:26:06 AM HCOM_non-employee_reimbursement_form.pdf Hi, Beth, Certainly! Please find it attached. Also, please mail the receipts to me at the following address: Hannah Bruner 79 JFK St. Box 84 Cambridge, MA 02155 Thanks, Beth! Hope you are well! Best, Hannah   From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Wednesday, April 08, 2015 2:24 PM To: Bruner, Hannah Subject: RE: RE:   Hi Hannah,   Can you send me the form for the reimbursement for the last HEPG meeting?   Thank you,   Beth   From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Thursday, March 19, 2015 2:01 PM To: Beth L. Soliere Subject: Re: RE:   Hi, Beth,  Oh, excellent-- we already have him registered and all set!  You are very welcome! Best, Hannah Sent from my iPhone On Mar 19, 2015, at 4:51 PM, "Beth L. Soliere" wrote: Hi Hannah  The name of the person is Lon Huber.  Thanks for the info on the taxi! . J   From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Thursday, March 19, 2015 1:07 PM To: Beth L. Soliere Subject: RE:   Hi, Beth, We’re not. I believe several people, myself included, are renting cars (it’s just a bit cheaper). Boston Corporate Coach is always good. They pick up from the San Francisco airport. It’ll be around $100. A standard taxi will run around $75. I hope this helps! Also, Jo-Ann mentioned Bob might bring along another gentleman. Could you please forward on his information, so we can make him a nametag, etc.? Thanks! Best, Hannah   From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Thursday, March 19, 2015 3:54 PM To: Bruner, Hannah Subject:   Hi Hannah- I am planning for Bob’s transportation from the airport to the hotel. Are you guys using anyone particular for this?   Beth Soliere, Executive Aide Commissioner Bob Stump Arizona Corporation Commission 1200 W. Washington Street Phoenix, AZ 85007 602-542-3935   From: To: Subject: Date: Beth L. Soliere Bob Stump Re: Commissioner Stump"s Room Reservation for HEPG"s March Meeting Monday, March 23, 2015 4:00:23 PM Yes. Lol.  I meant a one two bed room. :) Sent from my iPhone On Mar 23, 2015, at 3:53 PM, Bob Stump wrote: You mean for two. :-)  Sent from my iPhone On Mar 23, 2015, at 3:53 PM, Beth L. Soliere wrote: Yes. They already had you scheduled for one.  On Mar 23, 2015, at 3:49 PM, Bob Stump wrote: Thanks. Hope everyone was clear that there shouldn't be an extra charge  Sent from my iPhone On Mar 23, 2015, at 3:45 PM, Beth L. Soliere wrote: Yes, they have two beds for you. Maybe mention it again when you check in.  On Mar 23, 2015, at 3:38 PM, Bob Stump wrote: If they have them and there is no extra charge. Lon needs a place to crash so he doesn't have to drive so early tomorrow morn.  Sent from my iPhone On Mar 23, 2015, at 3:24 PM, Beth L. Soliere wrote: Ok. Do you want two beds? On Mar 23, 2015, at 3:13 PM, Bob Stump wrote: Could you ask hotel if there are two beds or one? Thx Sent from my iPhone On Mar 23, 2015, at 3:03 PM, Beth L. Soliere wrote: Begin forwarded message: From: "Bruner, Hannah" Date: February 26, 2015 at 8:13:12 AM MST To: "Beth L. Soliere" Subject: Commissioner Stump's  Room Reservation for  HEPG's March  Meeting Dear Beth,    We have confirmed Commissioner  Stump’s stay at the RitzCarlton in Half Moon Bay, CA for Monday and Tuesday evening. His confirmation number is  82564409. Checkin time is 4:00 pm on Monday, March 23, and checkout is 12:00 pm on Wednesday, March 25.   The RitzCarlton is located at 1 Miramontes Point Road in Half Moon Bay, CA 94019. The closest airport is San Francisco International (SFO), and a taxi may be taken from the airport to the hotel.   Should you have any questions or concerns, I will be happy to address them, or you may contact the hotel directly at (650) 7127000.   Have a nice day.   Best regards,     Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School 6174966760 Hannah_Bruner@hks.harvard.edu   From: To: Subject: Date: Bob Stump Beth L. Soliere Re: Commissioner Stump"s Room Reservation for HEPG"s March Meeting Monday, March 23, 2015 3:54:02 PM Hope Lon isn't up late playing video games.  Sent from my iPhone On Mar 23, 2015, at 3:53 PM, Beth L. Soliere wrote: Yes. They already had you scheduled for one.  On Mar 23, 2015, at 3:49 PM, Bob Stump wrote: Thanks. Hope everyone was clear that there shouldn't be an extra charge  Sent from my iPhone On Mar 23, 2015, at 3:45 PM, Beth L. Soliere wrote: Yes, they have two beds for you. Maybe mention it again when you check in.  On Mar 23, 2015, at 3:38 PM, Bob Stump wrote: If they have them and there is no extra charge. Lon needs a place to crash so he doesn't have to drive so early tomorrow morn.  Sent from my iPhone On Mar 23, 2015, at 3:24 PM, Beth L. Soliere wrote: Ok. Do you want two beds? On Mar 23, 2015, at 3:13 PM, Bob Stump wrote: Could you ask hotel if there are two beds or one? Thx Sent from my iPhone On Mar 23, 2015, at 3:03 PM, Beth L. Soliere wrote: Begin forwarded message: From: "Bruner, Hannah" Date: February 26, 2015 at 8:13:12 AM MST To: "Beth L. Soliere" Subject: Commissioner Stump's  Room Reservation for  HEPG's March  Meeting Dear Beth,    We have confirmed Commissioner  Stump’s stay at the RitzCarlton in Half Moon Bay, CA for Monday and Tuesday evening. His confirmation number is  82564409. Checkin time is 4:00 pm on Monday, March 23, and checkout is 12:00 pm on Wednesday, March 25.   The RitzCarlton is located at 1 Miramontes Point Road in Half Moon Bay, CA 94019. The closest airport is San Francisco International (SFO), and a taxi may be taken from the airport to the hotel.   Should you have any questions or concerns, I will be happy to address them, or you may contact the hotel directly at (650) 7127000.   Have a nice day.   Best regards,     Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School 6174966760 Hannah_Bruner@hks.harvard.edu   From: To: Subject: Date: Beth L. Soliere Bob Stump Fwd: Commissioner Stump"s Room Reservation for HEPG"s March Meeting Monday, March 23, 2015 3:03:15 PM Begin forwarded message: From: "Bruner, Hannah" Date: February 26, 2015 at 8:13:12 AM MST To: "Beth L. Soliere" Subject: Commissioner Stump's  Room Reservation for  HEPG's March  Meeting Dear Beth,    We have confirmed Commissioner  Stump’s stay at the Ritz-Carlton in Half Moon Bay, CA for Monday and Tuesday evening. His confirmation number is  82564409. Checkin time is 4:00 pm on Monday, March 23, and check-out is 12:00 pm on Wednesday, March 25.   The Ritz-Carlton is located at 1 Miramontes Point Road in Half Moon Bay, CA 94019. The closest airport is San Francisco International (SFO), and a taxi may be taken from the airport to the hotel.   Should you have any questions or concerns, I will be happy to address them, or you may contact the hotel directly at (650) 712-7000.   Have a nice day.   Best regards,     Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School 617-496-6760 Hannah_Bruner@hks.harvard.edu   From: To: Subject: Date: Beth L. Soliere Bob Stump RE: Cab Monday, March 23, 2015 10:17:24 AM Nevermind. I forgot it was HEPG. I got the confirmation for the cab to pick you up. I will let them know that there will be an additional person.  -----Original Message----From: Bob Stump Sent: Monday, March 23, 2015 4:00 AM To: Beth L. Soliere Subject: Cab Susan is on my flight and was interested in sharing the cab - could you kindly see if they'll do that Sent from my iPhone From: To: Subject: Date: Beth L. Soliere Bob Stump FW: Attire for HEPG Meeting: business casual Thursday, March 19, 2015 11:59:05 AM     From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Thursday, March 19, 2015 11:43 AM To: Mahoney, Jo-Ann Subject: Attire for HEPG Meeting: business casual   We look forward to seeing you at Half Moon Bay.  Attire for this California meeting will be business casual.  See you next week.  Jo-Ann     Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu     From: To: Subject: Date: Attachments: Bob Stump Beth L. Soliere; Lon Huber Fwd: HEPG Conference Logistics/Dinner Invitation Friday, March 06, 2015 2:39:18 PM HEPG_3_15_DraftAgenda_Speakers.docx ATT00001..htm CaliforniaRoadmap_2014.pdf ATT00002..htm Sent from my iPhone Begin forwarded message: From: "Mahoney, Jo-Ann" To: "Mahoney, Jo-Ann" Cc: "Bruner, Hannah" Subject: HEPG Conference Logistics/Dinner Invitation We look forward to your participation in the Harvard Electricity Policy Group Plenary Session to be held at the Ritz Carlton Half Moon Bay on Tuesday-Wednesday, March 24-25, 2015.  Our most recent agenda is attached.   Our conference reception and private dinner will be held on property on Tuesday evening, March 24 at Navio Restaurant.  You are welcome to bring a guest who is travelling with you.  Kindly rsvp to Hannah_Bruner@hks.harvard.edu.   We are also including some advanced reading, including the California Roadmap for energy storage (attached) and the executive summary and pilot details for an EPRI study on the integrated grid, which can be downloaded at the following sites: IG Executive Summary: http://www.epri.com/abstracts/Pages/ProductAbstract.aspx? ProductId=000000003002005177 Pilot Overview:  http://www.epri.com/abstracts/Pages/ProductAbstract.aspx? ProductId=000000003002005003          Pilots: http://www.epri.com/abstracts/Pages/ProductAbstract.aspx? ProductId=000000003002005004   I look forward to seeing you in California.   Best, Jo-Ann     Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu     HARVARD ELECTRICITY POLICY GROUP HARVARD ELECTRICITY POLICY GROUP SEVENTY-EIGHTH PLENARY SESSION Ritz-Carlton Half Moon Bay, CA TUESDAY AND WEDNESDAY, MARCH 24 - 25, 2015 DRAFT AGENDA Tuesday, March 24 8:30 am Breakfast and Informal Discussion 9:00 am Session One. Storage and the Economics of Clean Electricity: Can Expanded Storage Solve the Challenges of Increased Penetration of Intermittent Resources? Storage of electric energy has always played an important but relatively small role in the operation of power systems. Changes in load, power supply and transmission congestion all interact to create substantial variability across time and space. This variability creates the fundamental value of storage. Increased variability from increasing penetration of intermittent renewables is a central focus of planning and analysis for the power sector. The increased variability seems to call out for a great expansion of investment in storage. The recent CAISO storage “roadmap” is an example of the potential reach of storage to help moderate the economic and environmental footprint of the electricity sector. Do advances in storage technologies and a proliferation of new storage models create the prospect for a transformation of the electricity sector? Will storage be able to eliminate the effects of transmission congestion? What are the current economics of storage for energy arbitrage and ancillary services? What are the values that storage brings to the power system? What regional strategies are being pursued? Will storage be truly transformational, merely valuable, or highly overrated? Keith Casey, California Independent System Operator Paul Denholm, National Renewable Energy Laboratory Michael Rowand, Duke Energy Hossein Safaei, IHS Calgary PHONE 617-496-6760 FAX 617-495-1635 EMAIL HEPG@ksg.harvard.edu 79 John F. Kennedy Street, Box 84 Cambridge, Massachusetts 02138 www.hks.harvard.edu/hepg HEPG Agenda, March 24 - 25, 2015 Tuesday, March 24 (cont’d) 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Lunch 1:15 pm Session Two. Distributed Energy Resources and Distribution Systems: Are “DSOs” and More Sophisticated Planning and Network Pricing Needed? Distributed energy resources (DER) in the marketplace give rise to many issues, including the valuation of the units and pricing of their output. How does DER fit into the overall framework of the distribution system? The impact of a significant DER presence on the system is not only economic, but physical as well. Energy flows on the distribution grid are affected, the amount of investments in distribution upgrades and equipment such as transformers is likely to be heavily driven by the presence, location, and configuration of DER on the system, and the interaction of DER may, from time to time, adversely affect the ability of some DER to export from the premises where they are located. Distribution owning utilities themselves are entering the DER business and are effectively competitors of other DER providers, raising issues associated with vertical market power. Providing incentives for more efficient deployment of DER and accoutrements, providing for the possibility of more efficient alternatives to distribution upgrades, obviating vertical market power issues, and locational real-time prices for distribution, are all issues that policy makers, regulators, and market participants face now or will inevitably have to consider. Will we need independent Distribution System Operators? Should LMP distribution pricing be deployed? Should smart inverters be required of all DER providers? Finally, with or without all of the potential changes to distribution networks, how should planning and the processes for planning distribution networks be carried out to deal with the changing circumstances? Paul de Martini, Newport Consulting Barry Mather, National Renewable Energy Laboratory Bernie Neenan, Electric Power Research Institute Ron Nichols, Southern California Edison 2:45 pm Coffee Break 3:00 pm Discussion 4:15 pm Adjourn 6:30 pm Reception and Dinner HEPG Agenda, March 24 - 25, 2015 Wednesday, March 25 8:30 am Breakfast and Informal Discussion 9:00 am Session Three. ISO Governance and Processes: Are They Adequate in an Increasingly Dynamic Market? Is Some Harmonization Needed? The RTO/ISOs have processes and powers that vary from one to another. The reasons for the variations are derived from historical circumstances. Sections 205 and 206 of the Federal Power Act (“FPA”) establish the core substantive and procedural regulations governing the filing of rates, terms and conditions of wholesale power sales and transmission service in interstate commerce offered by public utilities subject to FERC jurisdiction. The governance rules of each RTO/ISO specify the internal procedures and stakeholder approvals necessary before the RTO staff is authorized to make such filings. As a result of different governance protocols, some markets are able to respond relatively quickly to changing economic and operating circumstances or perceived dysfunctions in market rules; other markets must navigate considerably more complex and time consuming internal stakeholder protocols before submitting a filing under Sections 205 and 206. In some cases, stakeholder groups may be able to delay or effectively block proposed submissions. At a time of rapid changes in market conditions and the substantial economic harms incurred by flawed or dysfunctional market rules, should FERC consider mandating a more consistent governance framework? What are the conflicts in the RTO/ISO responsibilities to support efficient markets, preserve reliability, and respect the wishes of the various stakeholders? Should FERC reassess the weighted voting procedures and look at reforming and possibly streamlining the stakeholder process? Ave Bie, Quarles and Brady Alexandra Klass, University of Minnesota Law School Roy Shanker, Independent Consultant Thomas Wrenbeck, ITC Holdings Corporation 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Adjourn + + + + + Advancing and + maximizing the +value of Energy Storage+ Technology + + + + A California Roadmap December 2014 This roadmap is a product of collaboration among three organizations – the California Independent System Operator (ISO), the California Public Utilities Commission (CPUC), and the California Energy Commission. It culminates years of work and input from more than 400 interested parties, including utilities, energy storage developers, generators, environmental groups and other industry stakeholders. DNV GL and Olivine, Inc. provided facilitation and consulting to support the development of the roadmap. While identified actions, venues and priorities will be used by each organization to inform future regulatory proceedings, initiatives and policies, it is not a commitment by any of the organizations to perform the actions. The team is deeply grateful for the time, effort and insight provided by stakeholders to shape the roadmap and looks forward to continuing this interaction as each organization embarks on the actions identified in this roadmap. Cover photos from left to right: Yerba Buena battery energy storage pilot in east San Jose courtesy of PG&E Interface in garage, customer side of Residential Energy Storage project courtesy of SMUD Tehachapi Storage Project courtesy of SCE Pad-mounted battery, utility side of Community Energy Storage project courtesy of SMUD Advancing and maximizing the value of Energy Storage Technology A California Roadmap December 2014 table of Contents Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Guidance to advance energy storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 State actions to advance energy storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Stakeholders voice challenges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Roadmap Actions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Planning. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Procurement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Rate treatment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Interconnection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Market participation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Next steps. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Appendix: Actions mapped to revenue opportunities, cost reduction and increased certainty. . . . . 17 Advancing and maximizing the value of Energy Storage Technology A California Roadmap December 2014 + + + + Executive Summary California is a worldwide leader in shifting to sustainable and renewable energy sources, including solar, wind and geothermal power, with the goal to reduce greenhouse gas emissions. But by its nature, electricity must be used the instant it is generated, which makes solar and wind resources challenging to manage on the power grid. Power from these renewable generation sources is produced at different times of the day, and often does not align with the instantaneous demand for electricity. Ground-breaking energy storage technology is changing all that. This technology harnesses energy generated by the sun during the day, wind gusts late in the afternoon, and energy from sources across the West. It stores it when consumption is low and puts it back onto the grid when needed at peak demand times or to compensate for unanticipated changes in renewable energy output. It is beginning to revolutionize the electric system by enabling increased renewables integration, increasing grid optimization, and reducing greenhouse gas emissions. Maximizing energy storage in the marketplace will take a network of policies, incentives, and processes to support innovation and manage risk over the next several years. While many organizations are testing energy storage technologies and systems, a comprehensive plan is needed to incorporate storage projects into the state’s grid at scale. In a fast-changing technological environment, it is important to have a clear vision of priorities and needed actions to realize 1 Advancing and maximizing the value of Energy Storage Technology A California Roadmap December 2014 ++ + + + + + the full benefits of energy storage. This document, the Energy Storage Roadmap, identifies actions that can help create a path to a sound marketplace for energy storage resources. The roadmap focuses on actions that address three categories of challenges expressed by stakeholders: • Expanding revenue opportunities Reducing costs of integrating and connecting to the grid • • Streamlining and spelling out policies and processes to increase certainty It analyzes the current state to identify needed actions, sets priorities for the next steps and defines the responsibilities of each organization to address the issues. The document highlights actions and will act as a platform to inform future regulatory proceedings, initiatives and policies, however, it does not lay out a plan to perform them. Work on many of those actions is already underway or planned. In general, high-priority concerns that need to be addressed include refining existing products and driving new ones to market; clarifying operational constraints to connecting energy storage to the grid; reducing costs of metering and connection; and creating a predictable and transparent process for commercializing and connecting storage projects. Deliberate collaboration in the execution of this roadmap will advance energy storage technology to better enable a more efficient, reliable and greener grid. + Introduction Guidance to advance energy storage California has been a dynamic force for transitioning to sustainable, renewable energy sources. The state has seen explosive growth in renewable energy in the past several years, particularly with solar installations more than doubling in recent years. The next step in this fast-moving shift towards a more sustainable grid is energy storage technology. Incorporating variable resources requires an accompanying portfolio of resources and contract provisions that provide operational flexibility to quickly change electricity production and consumption and maintain needed output levels for the time required. Energy storage resources are by their nature flexible resources and therefore beneficial to reliable, low-carbon grid operations. The purpose of this roadmap is to support the advancement of energy storage as a grid resource by identifying actions, their priority and the appropriate venue for implementing them. State actions to advance energy storage The state has taken action to advance energy storage, including the passage of Assembly Bill 2514 and the resulting California Public Utilities Commission (CPUC) decision for energy storage procurement targets for each of the Investor Owned Utilities (IOUs) totaling 1,325 MW to be completed by the end of 2020 and implemented by 2024.1 Additionally, the CPUC provides funding programs including Permanent Load Shifting and the Self Generation Incentive Program that provide incentives for adoption of customer-side energy storage.2 The California Energy Commission continues to fund critical research to further the effectiveness of energy storage as a viable grid resource through the Electric Program Investment Charge (EPIC).3 At the national level, the Federal Energy Regulatory Commission (FERC) Order No. 792, provides clarity through its direction to transmission providers to define electric storage devices as generating facilities enabling these resources to take advantage of generator interconnection procedures. Federal incentives such as the Business Energy Investment Tax Credit and the U.S. Department of Agriculture High Energy Cost Grant Program also provides support for energy storage.4 The United States Department of Energy provides grants to fund research and demonstration of new technologies including storage through their Advanced Research Projects Agency – Energy and Energy Efficiency and Renewable Energy offices.5 With this foundation in place, energy storage resources are beginning to enter the California market. As the three California IOUs prepared and carried out resource procurement to satisfy authorizations under the CPUC long-term procurement plan as well as fulfillment of the energy storage targets, stakeholders raised a number of questions that were either not addressed by current policy or unclear. This situation as well as a surge in energy storage projects seeking interconnection to the ISO grid also with questions needing clarification, propelled the CPUC, Energy Commission, and ISO to partner to develop this roadmap. AB2514 was approved on September 29, 2010 and was entered into California Public Utilities Code, Chapter 7.7, Sections 2835-2839; CPUC decision D14-10-045, October 16, 2014. 1 CPUC decision on permanent load shifting, D 12-04-045, implemented through resolution E-4586; http://www.cpuc.ca.gov/PUC/energy/DistGen/sgip/aboutsgip.htm 2 See for example PON-13-302 Developing Advanced Energy Storage Technology Solutions to Lower Costs and Achieve Policy Goals (http://www.energy.ca.gov/contracts/epic.html#PON-13-302) 3 4 Business Energy Investment Tax Credit (ITC), 26 USC § 48 and IRS Notice 2013-29; USDA - High Energy Cost Grant Program, 7 CFR 1709 5 https://eere-exchange.energy.gov/and http://www.arpa-e.energy.gov/?q=arpa-e-programs/range Advancing and maximizing the value of Energy Storage Technology A California Roadmap December 2014 2 Stakeholders voice challenges In crafting the roadmap, the team worked closely with interested stakeholders, including utilities, energy storage developers, generators, environmental groups, and others to identify challenges facing energy storage and propose actions to address them. Through stakeholder workshops and written comments, three general categories of challenges emerged: ability to realize the full revenue opportunities consistent with the value energy storage can provide; • • need to reduce cost of interconnection and ongoing operations; and need to increase certainty regarding processes and timelines. • Of the issues communicated, stakeholders most frequently expressed the inability to accurately value energy storage for all the services it can provide, especially as evaluated by utilities in their procurement processes. Two additional issues stand out with strong consensus for action. First, to clearly identify the need for flexible capacity and valuation 3 Advancing and maximizing the value of Energy Storage Technology A California Roadmap December 2014 of that capability in the CPUC resource adequacy program, and second, to clarify tariff treatment of storage facilities, in particular between charging and discharging of electricity. Energy storage stakeholders also expressed the need for clarity of wholesale market treatment including the application of the transmission access charge (TAC), available products, models, and rules to support their ability to build a business case. Stakeholders expressed less concern with the technical aspects of storage, such as standardized design and metering and telemetry requirements. + + + roadmap actions + ++ + + + + + The roadmap identifies actions to address the three categories of challenges described above. The venue for each action was also identified along with an assigned priority. The team organized the actions into five topic areas: planning, procurement, rate treatment, interconnection, and market participation.6 The following table contains the highest priority actions by topic area. Energy Storage Roadmap: highest priority actions 6 Planning CPUC Describe distribution grid operational needs and required resources characteristics. CPUC Facilitate clarification by IOUs of operational constraints that can limit the ability to accommodate interconnection on the distribution system. CPUC Examine and clarify opportunities for storage to defer or displace distribution upgrades. Procurement CPUC & Energy Commission Consider refinements to the valuation methodologies used by IOUs to support CPUC decisions on storage procurement and make models publicly available. CPUC Clarify rules for energy storage qualification and counting in an evolving Resource Adequacy (RA) framework. CPUC Consider “unbundling” flexible capacity RA counting. Rate treatment ISO Clarify wholesale rate treatment and ensure that the ISO tariff and applicable business practices manuals and other documentation provide sufficient information. CPUC Clarify and potentially modify net energy metering tariffs applicable to cases where energy storage is paired with renewable generators. The appendix provides a table that organized actions according to the category of challenge it addresses. Advancing and maximizing the value of Energy Storage Technology A California Roadmap December 2014 4 + Interconnection CPUC & ISO Clarify existing transmission and distribution interconnection processes, including developing integrated process flow charts and check lists. CPUC & ISO Evaluate opportunities to coordinate between Rule 21 and Wholesale Distribution Access Tariff (WDAT) to streamline interconnection processes and ability to efficiently move between processes. CPUC & ISO Evaluate the potential for a streamlined or ‘fast track’ distribution interconnection process for storage resources that meet certain use-case criteria. Market participation ISO Clarify existing ISO requirements, rules and market products for energy storage to participate in the ISO market. ISO Identify gaps and potential changes or additions to existing ISO requirements, rules, market products and models. ISO Where appropriate, expand options to current ISO requirements and rules for aggregations of distributed storage resources. Together, the actions form a roadmap toward potential solutions to advance the use of energy storage in California. It is beyond the scope to offer specific solutions. Instead, solutions will be developed through stakeholder participation at the appropriate venue. The ISO, CPUC, and Energy Commission each have their own processes for allocating resources and developing work plans, which will affect how and when each individual action item is addressed. Note the actions may be carried out differently than the identified priority. This may be due to actions already underway, complexity of a particular action, or through combining actions.7 A companion document to this roadmap captures actions taken or underway by each organization: http://www.caiso.com/informed/Pages/CleanGrid/EnergyStorageRoadmap.aspx 7 5 Advancing and maximizing the value of Energy Storage Technology A California Roadmap December 2014 Planning Planning and operation of the transmission and distribution grids need to be closely coordinated, however there are important differences in the regulatory framework, rules, and architecture. The ISO operates the high-voltage transmission grid and the wholesale energy markets, under the jurisdiction of the FERC. The lower voltage distribution grid is operated by IOUs, municipalities, and other regional entities under the oversight of a local regulatory authority.8 The architecture of the transmission and distribution grids differ. The transmission grid is a network where power flows can frequently change directions across the system, while the distribution system is a radial system typically with a single connection to the transmission system where power flows in one direction from the transmission grid to the end-user. As distribution-connected energy resources, including energy storage, become more prevalent, distribution system planning must evolve considering new requirements and capabilities brought by these resources to ensure grid reliability and safety. When performing grid planning, both the ISO and distribution utilities must have a complete understanding of the operational characteristics of storage resources connecting to their systems to assess and address their impact and contribution, including displacing or deferring infrastructure upgrades. Electric system planning requires clearly defining grid needs to reliably operate the transmission and distribution grids. In the case of the ISO, these needs can be addressed through transmission projects and resources located in specific areas that possess particular operating capabilities. The ISO identifies expected amounts of different types of capacity needed through studies executed in the annual Transmission Planning Process (TPP) and other published studies.9 The types of needs include system, local, and flexible capacity. System capacity reflects the amount of additional capacity needed to ensure the portfolio of resources is capable of meeting the peak forecast electricity demand. Local capacity needs indicate additional capacity required in a particular regional location to ensure the system can continue to operate when unanticipated generation or transmission outages occur. Flexible capacity refers to the need for resources that can provide ramping capability by increasing or decreasing output quickly. Since ramping capability is required to address needs across the entire ISO grid, flexible capacity is considered a system resource. These ISO studies are used to inform the CPUC’s Long-Term Procurement Planning (LTPP) process.10 This allows for the resulting resources authorized for IOU procurement to embody the needed operational characteristics. The ISO currently assesses the benefits of anticipated energy storage market resources coming on the system in addressing transmission needs identified in the annual TPP. When energy storage is found to be effective, ISO staff may recommend to the ISO Board that energy storage is the best way to address the need, rather than approving a transmission project. Stakeholders expressed that when energy storage was presented as a transmission asset rather than a market resource, more clarity was needed as to how that is done. This is included in the action items table at the end of this section. The Pacific Gas & Electric Helms Pumped Storage Plant represents the most well-known and oldest form of utility scale energy storage. Using two reservoirs at different elevations, water is released to produce electricity and then pumped back up to be stored as energy for use at a different time. The facility has been operational since 1984 and acts as a valuable market resource contributing to the reliable operation of the ISO grid. The CPUC is a local regulatory authority that has oversight over the energy service providers including the IOUs and community choice aggregators. Rules for the interconnection of generation resources on the distribution grid that intend to engage in wholesale transactions are under the jurisdiction of the FERC. 8 http://www.caiso.com/planning/Pages/TransmissionPlanning/Default.aspx. The Flexible Capacity study is known as the “Flexible Capacity Needs Assessment” and can be found at http://www.caiso.com/informed/Pages/StakeholderProcesses/FlexibleCapacityRequirements.aspx 9 10 http://www.cpuc.ca.gov/PUC/energy/Procurement/LTPP/ Advancing and maximizing the value of Energy Storage Technology A California Roadmap December 2014 6 The IOUs are currently developing Distribution Resource Plans as directed by the CPUC to fulfill a requirement of Assembly Bill 327.11 These plans will identify the optimal locations for distributed energy resources, including energy storage, on the distribution system. A working group called “More than Smart” is a companion effort to the CPUC proceeding to facilitate technical discussions and includes topics outside the current proceeding. One such topic is the need to define coordination between utility and ISO planning. This will ensure that assumptions made in the transmission planning process of the types, amounts, and locations of distributed energy resources are included in distribution planning. Conversely, as resources begin to materialize on the distribution system, assumptions in transmission planning can be adjusted. Planning action items 1 Describe distribution grid operational needs and required resources characteristics. CPUC High 2 Facilitate clarification by IOUs of operational constraints that can limit the ability to accommodate interconnection on the distribution system. CPUC High 3 Examine and clarify opportunities for storage to defer or displace distribution upgrades. CPUC High 4 Describe ISO grid operational needs and required resource characteristics. ISO Medium 5 Develop coordination process for transmission and distribution system planning. CPUC, ISO Medium 6 Clarify assessment of energy storage resources classified as transmission assets to defer or displace transmission upgrades. ISO Low Procurement Several stakeholders expressed the need for a common methodology and tools for evaluating storage for use by utilities and the CPUC in making procurement decisions. In its 2013 decision on storage, the CPUC identified several areas of value that should be considered in the IOU procurement filings.12 The decision also identified available tools to support valuation but stopped short of defining a specific methodology or tool to be used in future storage procurement cycles. In the decision, the CPUC concluded that each “utility should be allowed to propose its own methodology to evaluate the costs and benefits of bids and evaluate the full range of benefits and costs identified for energy storage in the use-case.” The decision further acknowledged that this approach gives IOUs wide latitude to use proprietary protocols for actual project selection. CPUC energy storage proceeding R.10-12-007, Decision D.13-10-040 12 7 This valuation includes defining products and services that can provide revenue to energy storage and other flexible resources suppliers. These products and services need to be grounded in the operational needs of the transmission and distribution systems. That means clearly defining grid Public Utilities Code Section 769 was instituted by Assembly Bill 327, Sec. 8 (Perea, 2013). This new code section requires the electrical corporations to file distribution resources plan proposals by July 1, 2015. According to the Code, these plan proposals will “identify optimal locations for the deployment of distributed resources.” It defines “distributed energy resources” as “distributed renewable generation resources, energy efficiency, energy storage, electric vehicles, and demand response technologies.” The Code also requires the CPUC to “review each distribution resources plan proposal submitted by an electrical corporation and approve, or modify and approve, a distribution resources plan for the corporation. The commission may modify any plan as appropriate to minimize overall system costs and maximize ratepayer benefit from investments in distributed resources.” Pursuant to Section 769, the CPUC instituted a rulemaking on August 13, 2014 (R. 14-08-013). 11 Under the Public Interest Energy Research (PIER) program, the Energy Commission funded research and development of storage evaluation tools and methodologies to address at least some of the needs in determining the value of storage for the California grid and for energy storage developers. Similarily, under the EPIC program, the Energy Commission also aims to fund the development of storage valuation methodologies and tools with the purpose of making such tools and methodologies transparent and publicly available. Advancing and maximizing the value of Energy Storage Technology A California Roadmap December 2014 Thermal energy storage represents another type of energy storage that can contribute to customer demand management as well as provide grid benefits. This type of storage technology reserves energy produced in the form of heat or cold for use at a different time. While thermal energy storage has historically been used mainly for customer demand management, recent procurement of 25.6 MW from Ice Energy by Southern California Edison (SCE) illustrates its value as a grid resource. The Ice Energy Ice Bear installations like this one at Kohl’s facility in Redding, CA will be used by SCE to reduce the demand on distribution infrastructure during peak periods. needs through planning processes as described in the previous section, prior to developing products or instituting tariff or procurement mechanisms. From the distribution perspective, developers contend that energy storage provides benefits to the distribution system, but tariffs are not in place to value these capabilities and procurement does not recognize these additional values. To date, there has not yet been sufficient experience to define and quantify these benefits and establish how these capabilities can be monetized. Load serving entities under CPUC jurisdiction receive guidance and procurement authorization through the CPUC LTPP and other proceedings. The CPUC requires the load serving entities under its jurisdiction to annually demonstrate that their procured resource portfolio meets system, local, and flexible capacity needs according to its rules and eligibility requirements. This assessment as well as modifications to rules and eligibility requirements are taken up annually in the CPUC Resource Adequacy (RA) proceeding.13 Under current RA rules, one component for a resource to be eligible to qualify as RA capacity, it must be found to be deliverable. This deliverability assessment is performed by the ISO and requires that the transmission system can deliver the output of the resource, along with all other resources, to meet planning reserve margin requirements, across the peak timeframe. The current study process for determining deliverability status is consistent with requirements for system and local RA resources as these needs are based on meeting resource shortage conditions during peak load. Flexible capacity, however, addresses ramping needs not resource shortage conditions during peak load. The current RA counting qualifies each resource as a system or local resource, with local resources also counting as system resources. Because flexible capacity is considered a system resource, this counting rule results in all resources being subject to the deliverability assessment. The potential “unbundling” of flexible capacity and clarification of counting rules will benefit energy storage developers by removing the deliverability assessment for those resources providing only flexible capacity. Procurement action items 7 Consider refinements to the valuation methodologies used by IOUs to support CPUC decisions on storage procurement and make models publicly available. CPUC, Energy Commission High 8 Clarify rules for energy storage qualification and counting in an evolving RA framework. CPUC High 9 Consider “unbundling” for flexible capacity RA counting. CPUC High 10 Prepare summary of efforts underway focused on developing models for energy storage valuation and plans public distribution. Energy Commission Medium 13 The current CPUC RA proceeding is R.14-10-010 Advancing and maximizing the value of Energy Storage Technology A California Roadmap December 2014 8 Rate treatment Since energy storage acts as both a generator and consumer of electricity, stakeholders questioned what rates, wholesale or retail, will apply when consuming electricity to charge the storage device as well as whether other charges that traditionally apply to consumption will be levied. wholesale market activities for positive (discharging) or negative (charging) energy dispatches will be settled at the wholesale market locational marginal price. The ISO considers storage resources in the charging mode as storing electricity for later resale in the markets, rather than consumption of this electricity. There are many ways that energy storage can be used. The CPUC in its recent energy storage proceeding defined a number of use cases to inform the determination of the procurement target as well as other ongoing and future policy initiatives. In general, as it pertains to rate treatment, it is important to distinguish two types of storage applications: 1) energy that is stored for later injection back to the grid to provide grid services, and 2) energy stored and injected at different times of the day to change consumption patterns. The second case typically occurs at a customer facility to help mitigate demand charges and minimize consumption during higher rate periods. When the energy storage resource is located on the distribution system or on the customer site behind the utility meter, and seeks participation in the wholesale market, the resource can use the FERC jurisdictional tariff governing access to the wholesale market called the WDAT.16 Stakeholders also questioned rate treatment for customer sites with a mix of resources that help meet local consumption needs and do not result in the net export of energy that want to provide wholesale grid service. For this case, the CPUC needs to determine rate treatment. Currently, utilities must file an application with the CPUC on a case-by-case basis to determine the rate treatment.17 To provide context for the needed actions, for the first case, grid services can be provided to the wholesale market or to the utilities for distribution system management. In the case that the energy reserved using storage technology is providing grid services to the wholesale market, the rate treatment is consistent with that of a generation resource.14 This treatment was clarified as part of the ISO’s recent energy storage interconnection stakeholder initiative.15 The energy storage resource As part of the Irvine Smart Grid Demonstration Project, Southern California Edison, instrumented a neighborhood with smart grid technology including energy storage. This project benefited from funding from the DOE and the Energy Commission to bring a variety of technologies, communication and control systems to the distribution system and the customer. Instrumentation at the customer’s homes included energy management systems, smart appliances, thermostats, electric vehicles, rooftop solar and energy storage. The project also included community energy storage, shown here, to provide capabilities across a larger area. This smart grid technology establishes the foundation that enables customers to provide automated responses to calls for changes in consumption. Taken together these responses can be a significant resource to help manage the electric grid. It will be important to clarify rate treatment to ensure these capabilities can be leveraged by the utility and the wholesale market. 14 FERC addressed the issue of storage charging under a PJM filing by stating that electricity “stored for later delivery” is not “end-use” consumption and is therefore not subject to the jurisdiction of regulatory authorities over retail costs. Docket ER10-1717-000 15 http://www.caiso.com/informed/Pages/StakeholderProcesses/EnergyStorageInterconnection.aspx 16 Each utility has a separate Wholesale Distribution Access Tariff (WDAT) and can be found on their respective websites http://www.pge.com/en/b2b/newgenerator/index.page https://www.sce.com/wps/portal/home/regulatory/open-access-information http://www.sdge.com/generation-interconnections/wholesale-generator-transmission-interconnections 17 9 One example is the requirement for SCE to file applications to determine rate treatment of the energy storage devices selected through the recent local capacity requirement procurement. This procurement focused on replacing the capacity lost because of the retirement of the San Onofre Generating Station. Advancing and maximizing the value of Energy Storage Technology A California Roadmap December 2014 As previously described, distribution grid services that energy storage technology could provide are not yet fully defined, nor are products available to monetize these services. Development of specific products and tariffs may need to be considered as distribution utility services emerge. For the second case, when energy storage is used by the customer to manage their energy costs, the CPUC jurisdictional retail rate is applied. However, stakeholders communicate the need to optimize the value of the energy storage sited with renewable generation such as rooftop solar. Stakeholders express that the current rules limit the ability to use a storage device to save electricity produced by a renewable resource for use at different times of day without affecting the ability of the host customer to receive net energy metering credit for those exports.18,19 Another component of rate treatment is whether other charges that traditionally apply to electricity consumption will be levied. For wholesale market participation, the ISO clarified the application of infrastructure charges including the transmission access charge (TAC), wheeling charges, and uplifts to energy storage in its recent energy storage interconnection initiative.20,21 In addition, the treatment of station power and round trip efficiency loss needs to be clarified and potentially refined.22,23 The ISO needs to ensure its documentation provides sufficient information and is updated as policies evolve. Rate treatment action items 11 Clarify wholesale rate treatment and ensure that the ISO tariff and applicable business practices manuals and other documentation provide sufficient information. ISO High 12 Clarify and potentially modify net energy metering tariffs applicable to cases where energy storage is paired with renewable generators. CPUC High 13 Clarify rate treatment for customer sites with a mix of resources that help meet local consumption needs and do not result in the net export of energy, and want to provide wholesale grid services. CPUC Medium 14 Evaluate the need and potential to define distribution level grid services and products. CPUC Medium 15 Consider a new proceeding to develop distribution grid services provided by distributed energy resources to the utility or other entities. CPUC Low Net energy metering is a tariff established to allow one meter at a customer site that measures the net of the renewable generation production against the customer’s electricity use. The customer is then charged or paid on the net amount according to the tariff. Storage devices paired with net energy metering-eligible generation facilities are governed by CPUC’s net energy metering tariff established through proceeding R.12-11-005 provided in decision D. 14-05-033 issued May 2014. 19 The CPUC recently opened proceeding R.14-07-002 to address net energy metering successor tariffs by December 31, 2015. 20 The transmission access charge is a charge paid by all utility distribution companies and metered sub-system operators with gross load in a participating transmission owner service territory. The access charge recovers the participating transmission owner’s transmission revenue requirement. 21 The wheeling access charge is the charge assessed by the ISO that is paid by a scheduling coordinator for the use of the ISO controlled grid for the transmission of energy from the ISO controlled grid for delivery to a point outside the transmission and distribution system of a participating transmission owner. 22 Station power is energy for operating electric equipment, or portions thereof, located on the generating unit site owned by the same entity that owns the generating unit, which electrical equipment is used exclusively for the production of energy and any useful thermal energy associated with the production of energy by the generating unit 23 Round trip efficiency losses refers to energy lost in the conversion between charging and discharging. 18 Advancing and maximizing the value of Energy Storage Technology A California Roadmap December 2014 10 Interconnection Most physical energy storage resources connecting to the utility or the ISO-managed electric grid must adhere to the established interconnection standards and processes. Interconnection tariffs outline the rules for installing or modifying the installation of an energy storage project. The interconnection process includes application and study phases that determine whether and what types of electric grid upgrades are needed to accommodate the project. Technical requirements include data, equipment, telemetry, and metering and can vary based on the type, location, size, and intended operation of the facility. The method for apportioning the costs of grid and facility upgrades as well as cost recovery differs based on the use of the resource and the interconnection tariff. There are three available interconnection tariffs that can apply. Generally, facilities connecting to the distribution system not intended for wholesale market participation, and facilities connecting behind a customer’s meter that may or may not result in a net export of energy, interconnect using the CPUC jurisdictional tariff Rule 21. Resources connecting to the distribution system planning to participate in the wholesale market use the FERC jurisdictional WDAT. Finally, energy storage resources interconnecting to the transmission system are governed by the ISO interconnection tariff.24 Stakeholders expressed the importance of having a clear and predictable interconnection process to support the ability to make accurate estimates of project cost as well as the time to bring a facility on line and begin providing services. Suggestions included developing an integrated process flowchart especially between Rule 21 and the utility WDAT, differentiating between interconnection levels, project configurations, and the project’s intended operating behavior based on the market products and services it will provide. Energy storage developers also stated the need to streamline the processes as well as develop a smooth transition process to move a project from Rule 21 to WDAT as business requirements change. In addition to interconnection process clarity, stakeholders communicated candidate areas for process streamlining, modification, or additions to address operational characteristics not currently considered. In particular, energy storage developers desire a “fast track” distribution interconnection process for those projects that have little impact on the distribution system. Several stakeholders view the addition of energy storage that reduces load without creating electricity export to be a candidate for a fast track process. Furthermore, the screens applied to determine eligibility to current fast track interconnection processes under Rule 21 and WDAT need to be reviewed and potentially revised. Additionally, questions remain about the interconnection options available to a customer-sited resource that does Several interesting configurations involving energy storage are emerging on customer sites. The Powertree installation shown here is located at a residential multi-unit dwelling and includes electric vehicle charging infrastructure as well as energy storage. Rooftop solar provides energy to the building tenants as well as for use to charge the battery. In addition to providing service to the building, Powertree is preparing to provide grid services to the wholesale market. This installation is one of the first of its type seeking to directly participate in the wholesale market and is exposing gaps and needs for interpretation in the current distribution interconnection process. The process has taken significantly more time than expected and has resulted in extensive studies, equipment reviews, duplicative metering and other equipment required by the existing processes. Powertree continues to work with the utility to resolve issues and fill gaps. This experience helped identify several roadmap actions that focus on bringing clarity as well as improvements to the interconnection process, installation and operational requirements, rate treatment and other areas. 24 New interconnection requests to the ISO grid are governed by the Generator Interconnection and Deliverability Allocation Procedures (GIDAP) approved by FERC in 2012. The GIDAP rules are contained in ISO Tariff Appendix DD. http://www.caiso.com/Documents/AppendixDD_GeneratorInterconnectionAndDeliverabiltyAllocationProcess_Dec19_2014.pdf 11 Advancing and maximizing the value of Energy Storage Technology A California Roadmap December 2014 not result in net energy export electricity but could be offered in the wholesale market. As previously described in the rate treatment section, stakeholders also communicate the desire to define and establish a new fee structure for the interconnection of non-exporting resources. The CPUC continues to work through Rule 21 policy issues where these topics may be considered.25 The ISO recently conducted a stakeholder process on energy storage interconnection and found that the ISO’s current rules can accommodate the interconnection of storage projects to the ISO grid consistent with the treatment of generators.26 To be treated consistently with generation means that it must respond to ISO dispatch instructions, including curtailment, to manage power flow on the transmission system during both charging and discharging operations. The ISO will consider updates to the energy storage interconnection rules based on its learning and experience with the energy storage interconnection requests currently being processed. Measuring electricity output and the ability to communicate information using standard methods is essential for all resource types and not unique to energy storage. Additionally, it is important to have standards for installations to ensure safety and reliability as well as streamlining installations. Telemetry refers to the measurement of real-time electricity production or consumption of an energy storage installation or other resource. Electric grid operators rely on this critical information to ensure reliability. Stakeholders conveyed concerns with the ISO telemetry requirements as well as the obligations imposed by the utility. Accuracy for telemetry is less strict than for metering used for settlement, however, because of its operational function, network connectivity must be available around the clock with low latency. Resource aggregations require an additional system function to determine the total real-time measurement of aggregate resource production or consumption. This telemetry aggregation function may directly combine the individual telemetry feeds from the individual resources to the aggregate level or may use a sampling of individual feeds to statistically create the aggregated total.27 Metering refers to the measurement of generation and consumption with strict standards for accuracy, security, and safety used to determine customer bills as well as payments and charges to all types of resources participating in the wholesale market.28 Stakeholders communicated that duplicative metering requirements increase installation as well as ongoing costs. Stakeholders cited instances when both a utility meter and ISO meter are required. This occurs when the energy storage resource is providing services to the wholesale market as well as to the distribution grid and potentially a utility customer. As technology continues to evolve, most standard energy storage installations will include embedded, integrated meters or other low cost solutions that are not yet acceptable by the utility or ISO as metering or telemetry solutions. Utilizing these on-board measurement devices, once proven as accurate and tamper-resistant, could significantly reduce cost for telemetry and metering. Both telemetry and metering require network connectivity to transport the measurement data to the utility and the ISO. For the ISO, this is typically provided over a leased line referred to in ISO documentation as the Energy Communication Network (ECN). The ISO has taken recent steps to allow communication over the internet in specific cases as means to reduce costs. Finally, stakeholders expressed concern over the lack of fire protection standards and codes applicable to energy storage. It was noted by stakeholders that “one-size-fits-all” ordinances may not always be feasible given the range of circumstances of various municipal and city regulations and codes. Needed actions could include examination of the current requirements and identification of best practices for consideration in statewide regulations or development of standards by developers such as Underwriters Laboratories (UL). Verification of interconnection to bring a facility on-line includes various tests and certifications. Stakeholders conveyed the need to review and revise the certification process for testing and certifying energy resources, especially in preparation for provision of ancillary services to the wholesale market. The existing approach designed for generators is not well suited for energy storage. Generators have mostly static expectations for output capabilities, while energy storage differs in its operation shifting from supply to consumption. Order Instituting Rulemaking on the Commission’s Own Motion to improve distribution level interconnection rules and regulations for certain classes of electric generators and electric storage resources, R.11-09-011 26 http://www.caiso.com/informed/Pages/StakeholderProcesses/EnergyStorageInterconnection.aspx 27 Depending on the market services provided, the ISO requires 4-second to 1-minute telemetry. 28 Depending on the market services provided, the ISO requires five-minute to hourly meter data reporting. 25 Advancing and maximizing the value of Energy Storage Technology A California Roadmap December 2014 12 Interconnection action items 16 Clarify existing transmission and distribution interconnection processes, including developing integrated process flow charts and check lists. CPUC, ISO High 17 Evaluate opportunities to coordinate between Rule 21 and WDAT to streamline interconnection processes and ability to efficiently move between processes. CPUC, ISO High 18 Evaluate the potential for a streamlined or ‘fast track’ distribution interconnection process for storage resources that meet certain use-case criteria. CPUC, ISO High 19 Evaluate defining and establishing a fee structure to interconnect non-exporting resources. CPUC High 20 Define and support entities collecting telemetry data from multiple facilities, to allow bulk submission of this data. ISO High 21 Review and potentially modify utility WDAT to incorporate applicable modifications consistent with the ISO interconnection tariff including adjustments that streamline requirements ISO, (FERC) Medium 22 Review ISO’s procedure for testing and certifying resources for ancillary services. ISO Medium 23 Evaluate expanding technology options for providing resource telemetry. ISO Medium 24 Initiate and administer a working group to evaluate common telemetry framework and recommend actions to standardize resource telemetry requirements. Energy Commission Medium 25 Evaluate and consider refinements to ISO telemetry requirements. ISO Medium 26 Research and evaluate refinements to IOU telemetry requirements. Energy Commission Medium 27 Initiate and administer a working group to research and recommend a certification process for integrated device metering that can be used in place of the ISO or utility meter. Energy Commission Medium 28 Evaluate the rules for certifying sub-metering and third-party meter data collection and consider a process to validate, estimate and edit meter data to expand options for sourcing revenue quality meter data. CPUC, Energy Commission Medium 29 Establish the value and develop a framework under which the ISO and utility can share metering and meter data. CPUC, Energy Commission, ISO Medium 30 Initiate and administer a working group to review existing fire protection codes and materials handling guidelines for various energy storage technologies and applications and identify best practices. Energy Commission, CPUC Medium 31 Initiate and administer a working group to review and determine applicability, scope, and consistency of UL and other certification requirements for energy storage systems. Energy Commission Medium 32 Evaluate establishing rules for utility subtractive metering for behind-the-meter wholesale resources to improve resource granularity, visibility, and clarity in retail billing. CPUC Low 13 Advancing and maximizing the value of Energy Storage Technology A California Roadmap December 2014 Market participation Market participation primarily refers to the participation of energy storage resources in the established ISO wholesale market. It also refers to the ability of these resources to provide additional services to the distribution utilities or the end-use customer whether the service is contracted for through a market or not. Stakeholders identified several challenges to market participation surrounding the specific requirements to provide metering and telemetry. Actions to address these challenges are included in the interconnection section above. storage and the CPUC begins to consider supporting policy, it will be important to include the rules that enable this multiple-use scenario. The most frequently provided example involves the energy storage device providing demand management at the customer site while also participating in the wholesale Energy storage developers articulated that one of the biggest challenges to realizing the full value of energy storage is the ability for a single installation to provide multiple services to several entities with compensation provided through different revenue streams. Stakeholders provided several examples of multiple-use applications of interest for energy storage. One such example involves the storage device serving as a transmission asset while also participating in the markets. This affords the energy storage developer greater certainty of revenues in that it could recover part of its costs through the TAC and also earn market revenues. FERC has not approved such an arrangement to the best of the ISO’s knowledge, and prior FERC orders identify the challenges and hurdles associated with classifying storage facilities.29 One critical concern, addressed in the Nevada Hydro order, is that the ISO cannot be responsible for determining the operation of a resource that it would compensate as it could affect market prices. Stakeholders also highlight an emerging scenario where the energy storage facility provides reliability services to the distribution grid and services to the wholesale market. Even though energy storage may provide benefits to the distribution system, tariffs and rules are not in place to value these capabilities and procurement does not recognize these additional values. As the utilities solidify distribution grid needs that may be satisfied by energy The sodium sulfur battery located at the Pacific Gas and Electric facility in Vaca-Dixon, CA was the first to provide services to the ISO market. Utility scale energy storage such as this one offers significant flexibility in balancing the grid under a variety of conditions. The potential operational benefits include: • reliability and flexible energy management – offsetting the variability of preferred resources such as wind and solar power • voltage support – helping maintain local grid voltage, which supports grid stability by providing a steady push of electrons across long-distance power lines • reserves – providing replacement reserves called upon when the grid is under stress • demand response and load management – flatting spikes in high consumer energy use, which helps bring down wholesale energy prices during peak periods, and increasing consumption during times of abundant low-cost supply 29 See Western Grid Development, LLC., 130 FERC ¶61,056, reh’g denied, 133 FERC ¶61,029 (2010); The Nevada Hydro Company, 122 FERC ¶61,272 (2008). See also Third Party Provision of Ancillary Services; Accounting and Financial Reporting for New Electric Storage Technologies, 135 FERC ¶61,240 (2011). Advancing and maximizing the value of Energy Storage Technology A California Roadmap December 2014 14 market. Stakeholders articulate that demand management actions, especially for peak-load occurs during a predictable range of time. The storage device could be reserved for this use during this time and participate in the ISO market the remainder of the time. Also, in the interest of maximizing revenue, stakeholders hold a perception that there are insufficient wholesale market products available to fully realize the value energy storage can provide. This perspective highlights the need for the ISO to communicate existing products and modeling options for market participation.30 Market products and models are developed to facilitate wholesale market procurement of needed services and capabilities. The ISO is engaging stakeholders in an initiative to develop a flexible ramping product to ensure sufficient amounts of ramping capability can be procured through economic bids. Preparing and discussing this information with stakeholders may result in the identification of gaps and opportunities to make changes to current requirements, rules, or market products. A gap that began to emerge during the roadmap effort involved the ability for a resource to be modeled as part of an aggregation with other resources. For example, developers are pursuing siting energy storage together with renewable generation resources. This has been referred to as a hybrid configuration and includes a broader set of combinations, including combinations with demand response. Beyond ISO market modeling, the CPUC should assess how each utility considers hybrid configurations based on its procurement targets and needs. In addition, where appropriate, the ISO should consider expanding options to current ISO requirement and rules for aggregations of distributed storage resources. Because the scope of possible multiple use and hybrid configurations is potentially quite large, stakeholders suggested that it would be useful to identify and prioritize storage configurations. For the higher priority configurations, the ISO or CPUC can identify key requirements and drivers and determine how best to support these configurations. Market participation action items 33 Clarify existing ISO requirements, rules and market products for energy storage to participate in the ISO market. ISO High 34 Identify gaps and potential changes or additions to existing ISO requirements, rules, market products and models. ISO High 35 Where appropriate, expand options to current ISO requirements and rules for aggregations of distributed storage resources. ISO High 36 Define and develop models and rules for multiple-use applications of storage. CPUC, ISO Medium 37 Identify and develop models of hybrid storage configurations for wholesale market participation. ISO Medium 38 For configurations of greatest interest or likelihood of near-term development, clarify the requirements and rules for participation. CPUC, ISO Medium 30 The various market models provide options for how the resource will be characterized and operated in the market. The Non-Generating Resource (NGR) model is the primary model used for energy storage, however, the proxy demand resource model, pumped storage, and NGR – Regulation Energy Management model are other options. 15 Advancing and maximizing the value of Energy Storage Technology A California Roadmap December 2014 + + + Next steps The roadmap effort fulfilled its objective to enhance the team’s understanding of challenges articulated by stakeholders and identified actions that can be taken to address these challenges. It was not the goal to create a timeline to carry out the actions, rather to assign priorities and identify appropriate venues to address them.31 This roadmap will be used by the CPUC, Energy Commission and the ISO to inform future regulatory proceedings, initiatives and policies. + ++ + + + + + Although CPUC staff participated actively in the roadmap development, staff cannot dictate future CPUC actions. Parties are encouraged to actively participate in CPUC proceedings to raise issues and work in collaboration with utilities and other stakeholder to affect desired policies. The best way for individuals and companies to follow these developments and track progress toward meeting goals is to become parties or to subscribe to relevant CPUC proceedings. 31 A companion document to this roadmap captures actions taken or underway by each organization: http://www.caiso.com/informed/Pages/CleanGrid/EnergyStorageRoadmap.aspx. Advancing and maximizing the value of Energy Storage Technology A California Roadmap December 2014 16 + Appendix: Actions mapped to revenue opportunities, cost reduction, and increased certainty Actions to increase revenue opportunities Venue Priority Section # Define grid needs to identify gaps in existing markets and identify new products • Describe CPUC High • Facilitate CPUC High • Describe ISO Medium Planning 4 • Develop CPUC, ISO Medium Planning 5 distribution grid operational needs and required resources characteristics. clarification by IOUs of operational constraints that can limit the ability to accommodate interconnection on the distribution system. ISO grid operational needs and required resources characteristics. coordination process for transmission and distribution system planning. Planning 1 Planning 2 Clarify existing wholesale market product and models available for energy storage • Clarify existing ISO requirements, rules and market products for energy storage to participate in the ISO market. ISO High Market Participation 33 Refine existing and add new wholesale and retail market products to meet grid needs • Examine CPUC High Planning 3 • Identify ISO High Market Participation 34 • Evaluate CPUC Medium Rate Treatment 14 • Clarify ISO Low Planning 6 • Clarify ISO High Rate Treatment 11 • Clarify CPUC High Rate Treatment 12 • Clarify CPUC Medium Rate Treatment 13 • Consider CPUC Low and clarify opportunities for storage to defer or displace distribution upgrades. gaps and potential changes or additions to existing ISO requirements, rules, market products and models. the need and potential to define distribution level grid services and products. assessment of energy storage resources classified as transmission assets to defer or displace transmission upgrades. Identify gaps in rate treatment and clarify if existing rules address gaps wholesale rate treatment and ensure that the ISO tariff and applicable business practices manuals and other documentation provide sufficient information. and potentially modify net energy metering tariffs applicable to cases where energy storage is paired with renewable generators. rate treatment for customer sites with a mix of resources that help meet local consumption needs and do not result in the net export of energy, and want to provide wholesale grid service. a new proceeding to develop distribution grid services provided by distributed energy resources to the utility or other entities. Rate Treatment 15 Determine storage configurations and multiple use applications to enable prioritization and development of requirements • Define and develop models and rules for multiple-use applications of storage. CPUC, ISO • Identify and develop models of hybrid storage configurations for wholesale ISO market participation. • For configurations of greatest interest or likelihood of near-term development, clarify the requirements and rules for participation. 17 Advancing and maximizing the value of Energy Storage Technology A California Roadmap December 2014 CPUC, ISO Medium Market Participation 36 Medium Market Participation 37 Medium Market Participation 38 Actions to increase revenue opportunities, continued Venue Priority Section # Assess existing methodologies for valuing energy storage and develop a common methodology. • Consider CPUC, Energy Commission High Procurement 7 • Clarify CPUC High Procurement 8 CPUC High Procurement 9 Energy Commission Medium Procurement 10 refinements to the valuation methodologies used by IOUs to support CPUC decisions on storage procurement and make models publicly available. rules for energy storage qualification and counting in an evolving RA framework. • Consider • Prepare “unbundling” for flexible capacity RA counting. summary of efforts underway focused on developing models for energy storage valuation and plans for public distribution. Advancing and maximizing the value of Energy Storage Technology A California Roadmap December 2014 18 Actions to reduce cost Venue Priority Section # Review interconnection process for distribution-connected resources to reduce costs • Evaluate CPUC High • Review ISO, (FERC) Medium Interconnection 21 • Review ISO Medium Interconnection 22 • Define ISO High Interconnection 20 • Where ISO High Market Participation 35 ISO Medium Interconnection 23 Energy Commission Medium Interconnection 24 defining and establishing a fee structure to interconnect non-exporting resources. and potentially modify utility WDAT to incorporate applicable modifications consistent with the ISO interconnection tariff including adjustments that streamline requirements. ISO’s procedure for testing and certifying resources for ancillary services. Interconnection 19 Review and modify telemetry requirements and support entities collecting telemetry data from multiple facilities, to allow bulk submission of this data. appropriate, expand options to current ISO requirements and rules for aggregations of distributed storage resources. • Evaluate expanding technology options for providing resource telemetry. • Initiate and administer a working group to evaluate common telemetry framework and recommend actions to standardize resource telemetry requirements. • Evaluate and consider refinements to ISO telemetry requirements. ISO Medium Interconnection 25 • Research and evaluate refinements to IOU telemetry requirements. Energy Commission Medium Interconnection 26 • Initiate Energy Commission Medium Interconnection 27 • Evaluate CPUC, Energy Commission Medium Interconnection 28 • Establish CPUC, Energy Commission, ISO Medium Interconnection 29 • Initiate Energy Commission, CPUC Medium Interconnection 30 • Evaluate CPUC Low Energy Commission Medium Interconnection 31 Review and modify metering requirements and administer a working group to research and recommend a certification process for integrated device metering that can be used in place of the ISO or utility meter. the rules for certifying sub-metering and third-party meter data collection and consider a process to validate, estimate and edit meter data to expand options for sourcing revenue quality meter data. the value and develop a framework under which the ISO and utility can share metering and meter data. and administer a working group to review existing fire protection codes and materials handling guidelines for various energy storage technologies and applications and identify best practices. establishing rules for utility subtractive metering for behind-the-meter wholesale resources to improve resource granularity, visibility, and clarity in retail billing. Interconnection 32 Assess codes and standards to identify gaps and best practices • Initiate and administer a working group to review and determine applicability, scope, and consistency of UL and other certification requirements for energy storage systems. 19 Advancing and maximizing the value of Energy Storage Technology A California Roadmap December 2014 Actions to increase certainty Venue Priority Section # Clarify interconnection processes to make it predictable and transparent • Clarify existing transmission and distribution interconnection processes, including developing integrated process flow charts and check lists. CPUC, High ISO Interconnection 16 • Evaluate opportunities to coordinate between Rule 21 and WDAT to streamline interconnection processes and ability to efficiently move between processes. CPUC, High ISO Interconnection 17 • Evaluate the potential for a streamlined or ‘fast track’ distribution interconnection process for storage resources that meet certain use-case criteria. CPUC, High ISO Interconnection 18 This roadmap and material generated in support of the roadmap can be found on the California ISO website: http://www.caiso.com/informed/Pages/CleanGrid/EnergyStorageRoadmap.aspx. For more information, please contact Heather Sanders at the California ISO, hsanders@caiso.com From: To: Subject: Date: Bruner, Hannah Beth L. Soliere Commissioner Stump"s Room Reservation for HEPG"s March Meeting Thursday, February 26, 2015 8:15:36 AM Dear Beth,    We have confirmed Commissioner  Stump’s stay at the Ritz-Carlton in Half Moon Bay, CA for Monday and Tuesday evening. His confirmation number is  82564409. Check-in time is 4:00 pm on Monday, March 23, and check-out is 12:00 pm on Wednesday, March 25.   The Ritz-Carlton is located at 1 Miramontes Point Road in Half Moon Bay, CA 94019. The closest airport is San Francisco International (SFO), and a taxi may be taken from the airport to the hotel.   Should you have any questions or concerns, I will be happy to address them, or you may contact the hotel directly at (650) 712-7000.   Have a nice day.   Best regards,     Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School 617-496-6760 Hannah_Bruner@hks.harvard.edu   From: To: Subject: Date: Beth L. Soliere Bob Stump RE: Emailing: HEPG.NewOrleans.Stump Monday, February 23, 2015 10:44:04 AM $555.40 -----Original Message----From: Bob Stump Sent: Monday, February 23, 2015 10:40 AM To: Beth L. Soliere Subject: Re: Emailing: HEPG.NewOrleans.Stump What was the amount again Sent from my iPhone > On Feb 23, 2015, at 12:38 PM, Beth L. Soliere wrote: > > Are you sure you haven't seen it? > > -----Original Message----> From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] > Sent: Monday, February 23, 2015 10:33 AM > To: Beth L. Soliere > Subject: RE: Emailing: HEPG.NewOrleans.Stump > > It  says Feb. 3. > Best, > Hannah > > -----Original Message----> From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] > Sent: Monday, February 23, 2015 12:34 PM > To: Bruner, Hannah > Subject: RE: Emailing: HEPG.NewOrleans.Stump > > How long ago does it say it was sent? > > -----Original Message----> From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] > Sent: Monday, February 23, 2015 10:28 AM > To: Beth L. Soliere > Subject: RE: Emailing: HEPG.NewOrleans.Stump > > Hello, Beth, > It says online that the requisition has  been  paid. Have you not received the check yet? > It says it was sent to Redacted - Personal Information > Let me know if you haven't, so I can contact Accounts Payable. > Thanks. > Best, > Hannah > > -----Original Message----> From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] > Sent: Monday, Hannah > Subject: RE: Emailing: HEPG.NewOrleans.Stump > > Hi Hannah, > > Just checking on the reimbursement for this. > > Thanks, > > Beth > > -----Original Message----> From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] > Sent: Wednesday, January 14, 2015 8:38 AM > To: Beth L. Soliere > Subject: RE: Emailing: HEPG.NewOrleans.Stump > > Hi, Beth, > Sure. The flight confirmation is fine. If you'll just email it to me, that would be great. Also, I received the receipts in the mail yesterday. Thank you for sending them. > Best wishes, > Hannah > > > > -----Original Message----> From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] > Sent: Tuesday, January 13, 2015 2:51 PM > To: Bruner, Hannah > Subject: RE: Emailing: HEPG.NewOrleans.Stump > > Hi Hannah, > > Is the flight confirmation from the airline okay to send? > > -----Original Message----> From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] > Sent: Tuesday, January 06, 2015 9:36 AM > To: Beth L. Soliere > Subject: RE: Emailing: HEPG.NewOrleans.Stump > > Hello, Beth, > I hope you've had a  nice holiday. Thank you for sending back the reimbursement form. When convenient, please send the original receipts to  my attention at the following  address:  >    Hannah Bruner >    HEPG >    79 JFK St., Box 84 >    Cambridge, MA 02155 > Thank you! > Best wishes, > Hannah > > -----Original Message----> From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] > Sent: Monday, December 29, 2014 2:57 PM > To: Bruner, Hannah > Subject: Emailing: HEPG.NewOrleans.Stump > > > Your message is ready to be sent with the following file or link attachments: > > HEPG.NewOrleans.Stump > > > Note: To protect against computer viruses, e-mail programs may prevent sending or receiving certain types of file attachments.  Check your e-mail security settings to determine how attachments are handled. From: To: Subject: Date: Bob Stump Beth L. Soliere FW: "Valuation of Distributed Solar: A Qualitative View" Wednesday, February 04, 2015 12:56:57 PM Could you print this out please     From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Wednesday, February 04, 2015 12:17 PM To: Bruner, Hannah Cc: ogg@dc-energy.com; mike.oldak@utc.org; lawrence.oliva@sce.com; Lourdes.Muga@sce.com; Francesco.Olivieri@northamerica.enel.it; arne@ethree.com; paul.omalley@txu.com; konaran@eei.org; john.oneal@mirant.com; thomas.oneill@comed.com; richard.oneill@ferc.gov; bethann.ross@ferc.gov; JerroldOpp@Yahoo.com; DemocracyAndRegulation@Yahoo.com; ren@ethree.com; tom.osterhus@sage-view.com; ott@pjm.com; linda.spreeman@pjm.com; dowens@eei.org; brandon.owens@ge.com; dozenne@caiso.com; rpablos@borderplexalliance.org; clem.palevich@constellation.com; cheryl.thornton@constellation.com; Pande, Rohini; mary.ellen.paravalos@us.ngrid.com; jparks@smud.org; jparsons@mit.edu; tw.patch@alaska.gov; kushal.patel@nera.com; Angela Paton; dpatton@potomaceconomics.com; 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marc.romito@aps.com; ken@kenrose.us; tom.rose@txu.com; juan_rosellon_2003; jrosellon@diw.de; rrosen@tellus.org; william_rosenberg@ksg.harvard.edu; david.rosenstein@conectiv.com; joseph.rosenthal@ct.gov; jrossi@law.fsu.edu; jrotger@ESAI.com; mrothleder@caiso.com; skapki@caiso.com; gabinete@semc.rs.gov.br; michael.rowand@duke-energy.com; john.w.rowe@exeloncorp.com; OLD; erherzfelder@yahoo.com; ARudkevich@crai.com; IRudkevich@edisonmission.com; leruff@gmail.com; crufin@suffolk.edu; Ruggie, John; jb.ruhl@vanderbilt.edu; pruiz@crai.com; trumsey@nyiso.com; bill.rupert@oeb.gov.on.ca; barneyrush@rushenergyconsulting.com; ner@cpuc.ca.gov; nur@cpuc.ca.gov; nicholas.ryan@yale.edu; hossein.safaei@ihs.com; ishwar.saini@macquarie.com; rcs@der.ucm.es; jsanders@caiso.com; apascuzzo@caiso.com; cjs@cpuc.ca.gov; valerie.malliett@cpuc.ca.gov; mark.sanford@ge.com; Dsanta@ingaa.org; santen, nidhi; joisad@gmail.com; rob_schaefer@transalta.com; tschatzki@analysisgroup.com; lschavrien@semprautilities.com; ARuiz@semprautilities.com; wscherman@gibsondunn.com; kschisler@enernoc.com; todd.schlaht@cmegroup.com; steven.schleimer@calpine.com; Krystin.Worsham@calpine.com; rschmal@mit.edu; dagmar@mit.edu; kschmidt@itctransco.com; jmiller@Itctransco.com; Janelle_Schmidt_1996; loriejschmidt@hotmail.com; schmidt.lorie@epa.gov; daniel_schrag@harvard.edu; jonathan.schrag@nyu.edu; arsphd@fuse.net; ted.shultz@duke-energy.com; sadrita.davis@duke-energy.com; russell.schussler@gatrans.com; as2@cpuc.ca.gov; dscott@icc.illinois.gov; cweller@icc.illinois.gov; ssegner@lspower.com; jsegrelles@cibelescajamadrid.es; cseidlits@txu.com; stefaan.sercu@gdfsuezna.com; Lina.Corinth@gdfsuezna.com; sanem.sergici@brattle.com; mshames@ucan.org; drroyshanker@comcast.net; john.shapiro@morganstanley.com; rshapiro@sempraglobal.com; TWehrman@sempra.com; sharp@dcenergy.com; sharp@rff.org; Voigt@rff.org; jshelk@epsa.org; SSmyth@epsa.org; suedsheridan@yahoo.com; Peter.Sherk@morganstanley.com; Debra.A.Smith@MorganStanley.com; shi_yaodong@sina.com; rshilts@cftc.gov; shogren@netspeed.com.au; j.p.shotwell@sce.com; marilyn.showalter@ppinet.org; marilyn.showalter@gmail.com; jsiegeladr@aol.com; jonathan.siegler@txu.com; jamie.simler@ferc.gov; bishu.chatterjee@cpuc.ca.gov; scott.mosbaugh@cpuc.ca.gov; phyllis.white@cpuc.ca.gov; julie.simon@ferc.gov; jsimonknoll@gmail.com; doug.simpson@aeso.ca; joel.singer@opg.com; harry.singh@gs.com; andrews@calpine.com; sbrady@calpine.com; smeers@core.ucl.ac.be; trsmith@bpa.gov; ASmith@crai.com; marsha.smith@puc.idaho.gov; Jean.Jewell@puc.idaho.gov; NSMITH@InterGen.com; tom.smith@opc.com; wdsmith@sempra.com; rodneydirect@mindspring.com; rsmith@southpointenergy.com; mary_h_smith@harvard.edu; barry.smitherman@rrc.state.tx.us; garnet.cantwell@rrc.state.tx.us; rsmutnyj@energy.state.ca.us; smutny@iepa.com; jamie@iepa.com; apsmyth@aep.com; kezdenek@aep.com; apsmyth@aep.com; tsnitchler@mcdonaldhopkins.com; leland.snook@aps.com; socolow@princeton.edu; kathleen.blake@nrc.gov; paul.sotkiewicz@pjm.com; joe.sowell@gatrans.com; david.m.sparby@xcelenergy.com; mspitzer@steptoe.com; d.springe@curb.kansas.gov; rstanfield@nrdc.org; astar@icc.illinois.gov; les.starck@sce.com; Tom.Starrs@sunpower.com; Stavins, Robert; michael@michaelstavy.com; csteger@nrdc.org; stelzer@aol.com; jennifer.sterling@exeloncorp.com; gary.stern@sce.com; tambre.dreiling@sce.com; stevens@dc-energy.com; Stock, James; rstoddard@crai.com; SWalsh@crai.com; Steven@stoft.com; g.strbac@imperial.ac.uk; strouk@pjm.com; Bob Stump; Beth L. Soliere; fsturzenegger@bancociudad.com.ar; ssuccar@nrdc.org; suetsugu@ja2.so-net.ne.jp; bashir_sufyan@yahoo.com; Carolyn.Denham@psc.alabama.gov; masullivan@hhlaw.com; rsundararajan@aep.com; Surana, Kavita; svanda@cablespeed.com; eric.svenson@pseg.com; Sweeney, Rich; jim.sweeney@stanford.edu; monos@stanford.edu; MSwider@nyiso.com; mark.sylvia@state.ma.us; sharon.harris@state.ma.us; sfszwed@firstenergycorp.com; nicholas.tackett@ferc.gov; humayun_tai@mckinsey.com; tmyhypp@gmail.com; james.tarpey@state.co.us; tate@dc-energy.com; fendley@dc-energy.com; herb.tate@sbcglobal.net; wtaylor@calpine.com; karen.taylor@oeb.gov.on.ca; rtempchin@eei.org; rtempchin@eei.org; btenenbaum@worldbank.org; cheryl.terry@aeso.ca; ctezak@stanfordeagle.com; bfthornt@tva.gov; stierney@analysisgroup.com; Mike.Tierney@enel.com; mike.tierney@enel.com; wallace.tillman@comcast.net; Alex.Tolstykh@morganstanley.com; mtoman@worldbank.org; Stomasky@mac.com; james.torgerson@uinet.com; bernice.herring@uinet.com; jim.torpey@sunpowercorp.com; rtorres@pampaenergia.com; mark.tourangeau@nexteraenergy.com; jtranen@lexecon.com; noel.trask@exeloncorp.com; jgtrawick@tva.gov; terencepohl@hotmail.com; terence.trennepohl@camposmello.adv.br; Tribuzi.giuseppe@ccse.cc; brian.tulloh@txu.com; rturner@entegrapower.com; keither.turner99@gmail.com; mario@psr-inc.com; vendean.vafiades@maine.edu; francesca.valente@enel.com; david.velazquez@conectiv.com; jan.vandokkum@utcpower.com; pvandore@cato.org; elise.lambrechts@auc.ab.ca; svangoor@sempraglobal.com; gvanwelie@iso-ne.com; charris@iso-ne.com; david.vanwinkle@gatrans.com; jvasconcelos@newes.eu; pvasington@analysisgroup.com; sundar.venkataraman@ge.com; vespolil@firstenergycorp.com; Montellab@firstenergycorp.com; rdawson@atcllc.com; jvoeck@atcllc.com; amvogel@aep.com; vogelsan@bu.edu; william.vonhoene@exeloncorp.com; concepcion.morales@exeloncorp.com; wwvonschack@energyeast.com; etdubrava@energyeast.com; maria.vouras@ferc.gov; jxw@vitol.com; cjwagner2006@msn.com; mwagner@edisonmission.com; sandra.waldstein@ferc.gov; sandra.waldstein@state.vt.us; dbwalker@edf.org; swalker@nrdc.org; cwall@broadelec.com; Jone-Lin.Wang@ihscera.com; pwarburg@comcast.net; brian.ward@ge.com; Liz.Anselmo@ge.com; christoph.weber@uni-duisburg-essen.de; hannes.weigt@unibas.ch; jens.weinmann@gmail.com; weinmann@esmt.org; Andrew_Weinstein@ferc.gov; rweishaa@mwn.com; DBushnel@mwn.com; kweiss@FIRSTSOLAR.COM; sweissman@law.berkeley.edu; thomas.l.welch@maine.gov; jbwellinghoff@stoel.com; jolette.westbrook@state.ma.us; weston@occ.state.oh.us; rweston@raponline.org; howard.wetston@oeb.gov.on.ca; rose.cuoppolo@oeb.gov.on.ca; kwhitaker@nyiso.com; bill@dgardiner.com; whiteg3@michigan.gov; SimpsonS4@michigan.gov; om; swhitley@nyiso.com; degan@nyiso.com; wilde@dc-energy.com; cespedes@dean.com; lloyd.will@db.com; willcox@dc-energy.com; paulw.leg@verizon.net; hwilliams@psc.state.md.us; lwillick@lspower.com; twilson@epri.com; jwilson@wilsonenec.com; twinter@amsuper.com; stanwise@psc.state.ga.us; salliek@psc.state.ga.us; former email address; wolak@zia.stanford.edu; wolfram@haas.berkeley.edu; pat@patwood.net; lwood@edisonfoundation.net; carlwwood@verizon.net; pat@wood3resources.com; john.woodley@morganstanley.com; amy.martin@morganstanley.com; pwoodlock@yahoo.com; fiona.woolf@londoneconomics.com; eric@strategyi.com; wright2192@sbcglobal.net; rudolph.wynter@nationalgrid.com; jeanie.soto@nationalgrid.com; joseph.yan@sce.com; lloyd.yates@duke-energy.com; wyeager@misoenergy.org; kyeager@epri.com; stowle@epri.com; alta.yen@ge.com; asst.; hyoshimura@iso-ne.com; sandie.young@bctc.com; byoung@hunton.com; kzadlo@calpine.com; hlzang@yahoo.com; Fan_Zhang_2004; audrey.zibelman@dps.ny.gov; carl.zichella@sierraclub.org; lynda.ziegler@sce.com; kathryn.erickson@sce.com; dziegner@urc.in.gov Subject: “Valuation of Distributed Solar: A Qualitative View”   Good afternoon: I would like to take a moment to bring your attention to “Valuation of Distributed Solar: A Qualitative View,” a paper recently published in The Electric Journal and written by HEPG Executive Director Ashley Brown in collaboration with Jillian Bunyan of Greenberg Taurig. To read the full article, please follow the link below: http://hks.harvard.edu/hepg/Papers/2014/12.14/Brown%20%20Valuation%20of%20%20Distributed%20Solar%20%2011.14.pdf   I hope you find this reading of interest.   Best regards,     Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School 617-496-6760 Hannah_Bruner@hks.harvard.edu   From: To: Subject: Date: Attachments: Bob Stump Beth L. Soliere FW: HEPG Confirmation of March Attendance Wednesday, February 04, 2015 12:56:11 PM HEPG_3_15_DraftAgenda.docx HEPG_3_15_DraftAgenda.pdf     From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Wednesday, February 04, 2015 12:53 PM To: Mahoney, Jo-Ann Subject: HEPG Confirmation of March Attendance We look forward to your participation in the next Harvard Electricity Policy Group plenary session on Tuesday-Wednesday, March 24-25, 2015 at the Ritz Carlton Half Moon Bay, outside of San Francisco.  We will be discussing energy storage and the economics of clean electricity, distributed generation operations, and ISO governance.  Our agenda, with topic descriptions, is attached.    Best regards, Jo-Ann     Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu         HARVARD ELECTRICITY POLICY GROUP HARVARD ELECTRICITY POLICY GROUP SEVENTY-EIGHTH PLENARY SESSION Ritz-Carlton Half Moon Bay, CA TUESDAY AND WEDNESDAY, MARCH 24 - 25, 2015 DRAFT AGENDA Tuesday, March 24 8:30 am Breakfast and Informal Discussion 9:00 am Session One. Storage and the Economics of Clean Electricity: Can Expanded Storage Solve the Challenges of Increased Penetration of Intermittent Resources? Storage of electric energy has always played an important but relatively small role in the operation of power systems. Changes in load, power supply and transmission congestion all interact to create substantial variability across time and space. This variability creates the fundamental value of storage. Increased variability from increasing penetration of intermittent renewables is a central focus of planning and analysis for the power sector. The increased variability seems to call out for a great expansion of investment in storage. The recent CAISO storage “roadmap” is an example of the potential reach of storage to help moderate the economic and environmental footprint of the electricity sector. Do advances in storage technologies and a proliferation of new storage models create the prospect for a transformation of the electricity sector? Will storage be able to eliminate the effects of transmission congestion? What are the current economics of storage for energy arbitrage and ancillary services? What are the values that storage brings to the power system? What regional strategies are being pursued? Will storage be truly transformational, merely valuable, or highly overrated? PHONE 617-496-6760 FAX 617-495-1635 EMAIL HEPG@ksg.harvard.edu 79 John F. Kennedy Street, Box 84 Cambridge, Massachusetts 02138 www.hks.harvard.edu/hepg HEPG Agenda, March 24 - 25, 2015 Tuesday, March 24 (cont’d) 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Lunch 1:15 pm Session Two. Distributed Energy Resources and Distribution Systems: Are “DSOs” and More Sophisticated Planning and Network Pricing Needed? Distributed energy resources (DER) in the marketplace give rise to many issues, including the valuation of the units and pricing of their output. How does DER fit into the overall framework of the distribution system? The impact of a significant DER presence on the system is not only economic, but physical as well. Energy flows on the distribution grid are affected, the amount of investments in distribution upgrades and equipment such as transformers is likely to be heavily driven by the presence, location, and configuration of DER on the system, and the interaction of DER may, from time to time, adversely affect the ability of some DER to export from the premises where they are located. Distribution owning utilities themselves are entering the DER business and are effectively competitors of other DER providers, raising issues associated with vertical market power. Providing incentives for more efficient deployment of DER and accoutrements, providing for the possibility of more efficient alternatives to distribution upgrades, obviating vertical market power issues, and locational real-time prices for distribution, are all issues that policy makers, regulators, and market participants face now or will inevitably have to consider. Will we need independent Distribution System Operators? Should LMP distribution pricing be deployed? Should smart inverters be required of all DER providers? Finally, with or without all of the potential changes to distribution networks, how should planning and the processes for planning distribution networks be carried out to deal with the changing circumstances? 2:45 pm Coffee Break 3:00 pm Discussion 4:15 pm Adjourn 6:30 pm Reception and Dinner HEPG Agenda, March 24 - 25, 2015 Wednesday, March 25 8:30 am Breakfast and Informal Discussion 9:00 am Session Three. ISO Governance and Processes: Are They Adequate in an Increasingly Dynamic Market? Is Some Harmonization Needed? The RTO/ISOs have processes and powers that vary from one to another. The reasons for the variations are derived from historical circumstances. Sections 205 and 206 of the Federal Power Act (“FPA”) establish the core substantive and procedural regulations governing the filing of rates, terms and conditions of wholesale power sales and transmission service in interstate commerce offered by public utilities subject to FERC jurisdiction. The governance rules of each RTO/ISO specify the internal procedures and stakeholder approvals necessary before the RTO staff is authorized to make such filings. As a result of different governance protocols, some markets are able to respond relatively quickly to changing economic and operating circumstances or perceived dysfunctions in market rules; other markets must navigate considerably more complex and time consuming internal stakeholder protocols before submitting a filing under Sections 205 and 206. In some cases, stakeholder groups may be able to delay or effectively block proposed submissions. At a time of rapid changes in market conditions and the substantial economic harms incurred by flawed or dysfunctional market rules, should FERC consider mandating a more consistent governance framework? What are the conflicts in the RTO/ISO responsibilities to support efficient markets, preserve reliability, and respect the wishes of the various stakeholders? Should FERC reassess the weighted voting procedures and look at reforming and possibly streamlining the stakeholder process? 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Adjourn HARVARD ELECTRICITY POLICY GROUP HARVARD ELECTRICITY POLICY GROUP SEVENTY-EIGHTH PLENARY SESSION Ritz-Carlton Half Moon Bay, CA TUESDAY AND WEDNESDAY, MARCH 24 - 25, 2015 DRAFT AGENDA Tuesday, March 24 8:30 am Breakfast and Informal Discussion 9:00 am Session One. Storage and the Economics of Clean Electricity: Can Expanded Storage Solve the Challenges of Increased Penetration of Intermittent Resources? Storage of electric energy has always played an important but relatively small role in the operation of power systems. Changes in load, power supply and transmission congestion all interact to create substantial variability across time and space. This variability creates the fundamental value of storage. Increased variability from increasing penetration of intermittent renewables is a central focus of planning and analysis for the power sector. The increased variability seems to call out for a great expansion of investment in storage. The recent CAISO storage “roadmap” is an example of the potential reach of storage to help moderate the economic and environmental footprint of the electricity sector. Do advances in storage technologies and a proliferation of new storage models create the prospect for a transformation of the electricity sector? Will storage be able to eliminate the effects of transmission congestion? What are the current economics of storage for energy arbitrage and ancillary services? What are the values that storage brings to the power system? What regional strategies are being pursued? Will storage be truly transformational, merely valuable, or highly overrated? PHONE 617-496-6760 FAX 617-495-1635 EMAIL HEPG@ksg.harvard.edu 79 John F. Kennedy Street, Box 84 Cambridge, Massachusetts 02138 www.hks.harvard.edu/hepg HEPG Agenda, March 24 - 25, 2015 Tuesday, March 24 (cont’d) 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Lunch 1:15 pm Session Two. Distributed Energy Resources and Distribution Systems: Are “DSOs” and More Sophisticated Planning and Network Pricing Needed? Distributed energy resources (DER) in the marketplace give rise to many issues, including the valuation of the units and pricing of their output. How does DER fit into the overall framework of the distribution system? The impact of a significant DER presence on the system is not only economic, but physical as well. Energy flows on the distribution grid are affected, the amount of investments in distribution upgrades and equipment such as transformers is likely to be heavily driven by the presence, location, and configuration of DER on the system, and the interaction of DER may, from time to time, adversely affect the ability of some DER to export from the premises where they are located. Distribution owning utilities themselves are entering the DER business and are effectively competitors of other DER providers, raising issues associated with vertical market power. Providing incentives for more efficient deployment of DER and accoutrements, providing for the possibility of more efficient alternatives to distribution upgrades, obviating vertical market power issues, and locational real-time prices for distribution, are all issues that policy makers, regulators, and market participants face now or will inevitably have to consider. Will we need independent Distribution System Operators? Should LMP distribution pricing be deployed? Should smart inverters be required of all DER providers? Finally, with or without all of the potential changes to distribution networks, how should planning and the processes for planning distribution networks be carried out to deal with the changing circumstances? 2:45 pm Coffee Break 3:00 pm Discussion 4:15 pm Adjourn 6:30 pm Reception and Dinner HEPG Agenda, March 24 - 25, 2015 Wednesday, March 25 8:30 am Breakfast and Informal Discussion 9:00 am Session Three. ISO Governance and Processes: Are They Adequate in an Increasingly Dynamic Market? Is Some Harmonization Needed? The RTO/ISOs have processes and powers that vary from one to another. The reasons for the variations are derived from historical circumstances. Sections 205 and 206 of the Federal Power Act (“FPA”) establish the core substantive and procedural regulations governing the filing of rates, terms and conditions of wholesale power sales and transmission service in interstate commerce offered by public utilities subject to FERC jurisdiction. The governance rules of each RTO/ISO specify the internal procedures and stakeholder approvals necessary before the RTO staff is authorized to make such filings. As a result of different governance protocols, some markets are able to respond relatively quickly to changing economic and operating circumstances or perceived dysfunctions in market rules; other markets must navigate considerably more complex and time consuming internal stakeholder protocols before submitting a filing under Sections 205 and 206. In some cases, stakeholder groups may be able to delay or effectively block proposed submissions. At a time of rapid changes in market conditions and the substantial economic harms incurred by flawed or dysfunctional market rules, should FERC consider mandating a more consistent governance framework? What are the conflicts in the RTO/ISO responsibilities to support efficient markets, preserve reliability, and respect the wishes of the various stakeholders? Should FERC reassess the weighted voting procedures and look at reforming and possibly streamlining the stakeholder process? 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Adjourn From: To: Subject: Date: Bruner, Hannah Bob Stump RE: Important Information for HEPG"s March 2015 Conference Tuesday, February 03, 2015 8:48:30 AM Hello, again, We're delighted you will be able to attend. I keep forgetting to send you something. I've made a note to send a story this evening. My apologies. Best, Hannah -----Original Message----From: Bob Stump [mailto:bstump@azcc.gov] Sent: Sunday, February 01, 2015 5:07 PM To: Bruner, Hannah Subject: Re: Important Information for HEPG's March 2015 Conference Looking forward to it! Almost as much as reading your work. :-) Best, Bob Sent from my iPhone On Jan 30, 2015, at 11:08 AM, Bruner, Hannah > wrote: Good afternoon, As promised, I am following up with details on the conference venue and registration for the next meeting of the Harvard Electricity Policy Group. This session will be held outside San Francisco, CA at the Ritz-Carlton Half Moon Bay on the dates of Tuesday, March 24 and Wednesday, March 25. We are excited to announce the panel titles for this session.  They are as follows: ·         “Distributed Energy Resources and Distribution Systems: Are “DSOs” and More Sophisticated Planning and Network Pricing Needed?” ·         “Storage and the Economics of Clean Electricity: Can Expanded Storage Solve the Challenges of Increased Penetration of Intermittent Resources?” ·         “ISO Governance and Processes: Are They Adequate in an Increasingly Dynamic Market? Is Some Harmonization Needed?.” Please see the panel descriptions at the end of this email. HEPG will arrange a room for you for Monday, March 23 and Tuesday, March 24. Kindly, make your own travel arrangements, and HEPG will reimburse your travel expenses after the conference. We hope you will be able to join us in California. If so, please return the attached registration form to my attention, so we can reserve your space. Our registration deadline is quickly approaching on Friday, February 20. Have a wonderful weekend, and please do not hesitate to contact me with any questions or concerns you may have. Distributed Energy Resources and Distribution Systems: Are “DSOs” and More Sophisticated Planning and Network Pricing Needed? Distributed energy resources (DER) in the marketplace give rise to many issues, including the valuation of the units and pricing of their output.  How does DER fit into the overall framework of the distribution system? The impact of a significant DER presence on the system is not only economic, but physical as well. Energy flows on the distribution grid are affected, the amount of investments in distribution upgrades and equipment such as transformers is likely to be heavily driven by the presence, location, and configuration of DER on the system, and the interaction of DER may, from time to time, adversely affect the ability of some DER to export from the premises where they are located.  Distribution owning utilities themselves are entering the DER business and are effectively competitors of other DER providers, raising issues associated with vertical market power. Providing incentives for more efficient deployment of DER and accoutrements, providing for the possibility of more efficient alternatives to distribution upgrades, obviating vertical market power issues, and locational real-time prices for distribution, are all issues that policy makers, regulators, and market participants face now or will inevitably have to consider. Will we need independent Distribution System Operators? Should LMP distribution pricing be deployed? Should smart inverters be required of all DER providers? Finally, with or without all of the potential changes to distribution networks, how should planning and the processes for planning distribution networks be carried out to deal with the changing circumstances? Storage and the Economics of Clean Electricity:  Can Expanded Storage Solve the Challenges of Increased Penetration of Intermittent Resources? Storage of electric energy has always played an important but relatively small role in the operation of power systems.  Changes in load, power supply and transmission congestion all interact to create substantial variability across time and space.  This variability creates the fundamental value of storage.  Increased variability from increasing penetration of intermittent renewables is a central focus of planning and analysis for the power sector.  The increased variability seems to call out for a great expansion of investment in storage.   The recent CAISO storage “roadmap” is an example of the potential reach of storage to help moderate the economic and environmental footprint of the electricity sector.  Do advances in storage technologies and a proliferation of new storage models create the prospect for a transformation of the electricity sector?  Will storage be able to eliminate the effects of transmission congestion?  What are the current economics of storage for energy arbitrage and ancillary services?  What are the values that storage brings to the power system?  What regional strategies are being pursued?  Will storage be truly transformational, merely valuable, or highly overrated? ISO Governance and Processes: Are They Adequate in an Increasingly Dynamic Market? Is Some Harmonization Needed? The RTO/ISOs have processes and powers that vary from one to another. The reasons for the variations are derived from historical circumstances.  Sections 205 and 206 of the Federal Power Act (“FPA”) establish the core substantive and procedural regulations governing the filing of rates, terms and conditions of wholesale power sales and transmission service in interstate commerce offered by public utilities subject to FERC jurisdiction. The governance rules of each RTO/ISO specify the internal procedures and stakeholder approvals necessary before the RTO staff are authorized to make such filings. As a result of different governance protocols, some markets are able to respond relatively quickly to changing economic and operating circumstances or perceived dysfunctions in market rules; other markets must navigate considerably more complex and time consuming internal stakeholder protocols before submitting a filing under Sections 205 and 206.  In some cases, stakeholder groups may be able to delay or effectively block proposed submissions.  At a time of rapid changes in market conditions and the substantial economic harms incurred by flawed or dysfunctional market rules, should FERC consider mandating a more consistent governance framework?  What are the conflicts in the RTO/ISO responsibilities to support efficient markets, preserve reliability, and respect the wishes of the various stakeholders? Should FERC reassess the weighted voting procedures and look at reforming and possibly streamlining the stakeholder process? Warm regards, Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School 617-496-6760 Hannah_Bruner@hks.harvard.edu Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School 617-496-6760 Hannah_Bruner@hks.harvard.edu From: To: Subject: Date: Attachments: Bob Stump Beth L. Soliere Fwd: Important Information for HEPG"s March 2015 Conference Sunday, February 01, 2015 3:08:51 PM Commissioner Registration_form_3 15.docx ATT00001..htm Sent from my iPhone Begin forwarded message: From: "Bruner, Hannah" Date: January 30, 2015 at 11:06:09 AM MST To: "Bruner, Hannah" Subject: Important Information for HEPG's March 2015 Conference Good afternoon,   As promised, I am following up with details on the conference venue and registration for the next meeting of the Harvard Electricity Policy Group.   This session will be held outside San Francisco, CA at the Ritz-Carlton Half Moon Bay on the dates of Tuesday, March 24 and Wednesday, March 25.   We are excited to announce the panel titles for this session.  They are as follows:  ·         “Distributed Energy Resources and Distribution Systems: Are “DSOs” and More Sophisticated Planning and Network Pricing Needed?” ·         “Storage and the Economics of Clean Electricity: Can Expanded Storage Solve the Challenges of Increased Penetration of Intermittent Resources?” ·         “ISO Governance and Processes: Are They Adequate in an Increasingly Dynamic Market? Is Some Harmonization Needed?.”   Please see the panel descriptions at the end of this email.     HEPG will arrange a room for you for Monday, March 23 and Tuesday, March 24. Kindly, make your own travel arrangements, and HEPG will reimburse your travel expenses after the conference.   We hope you will be able to join us in California. If so, please return the attached registration form to my attention, so we can reserve your space. Our registration deadline is quickly approaching on Friday, February 20.   Have a wonderful weekend, and please do not hesitate to contact me with any questions or concerns you may have.   Distributed Energy Resources and Distribution Systems: Are “DSOs” and More Sophisticated Planning and Network Pricing Needed? Distributed energy resources (DER) in the marketplace give rise to many issues, including the valuation of the units and pricing of their output.  How does DER fit into the overall framework of the distribution system? The impact of a significant DER presence on the system is not only economic, but physical as well. Energy flows on the distribution grid are affected, the amount of investments in distribution upgrades and equipment such as transformers is likely to be heavily driven by the presence, location, and configuration of DER on the system, and the interaction of DER may, from time to time, adversely affect the ability of some DER to export from the premises where they are located.  Distribution owning utilities themselves are entering the DER business and are effectively competitors of other DER providers, raising issues associated with vertical market power. Providing incentives for more efficient deployment of DER and accoutrements, providing for the possibility of more efficient alternatives to distribution upgrades, obviating vertical market power issues, and locational real-time prices for distribution, are all issues that policy makers, regulators, and market participants face now or will inevitably have to consider. Will we need independent Distribution System Operators? Should LMP distribution pricing be deployed? Should smart inverters be required of all DER providers? Finally, with or without all of the potential changes to distribution networks, how should planning and the processes for planning distribution networks be carried out to deal with the changing circumstances?   Storage and the Economics of Clean Electricity:  Can Expanded Storage Solve the Challenges of Increased Penetration of Intermittent Resources? Storage of electric energy has always played an important but relatively small role in the operation of power systems.  Changes in load, power supply and transmission congestion all interact to create substantial variability across time and space.  This variability creates the fundamental value of storage.  Increased variability from increasing penetration of intermittent renewables is a central focus of planning and analysis for the power sector.  The increased variability seems to call out for a great expansion of investment in storage.   The recent CAISO storage “roadmap” is an example of the potential reach of storage to help moderate the economic and environmental footprint of the electricity sector.  Do advances in storage technologies and a proliferation of new storage models create the prospect for a transformation of the electricity sector?  Will storage be able to eliminate the effects of transmission congestion?  What are the current economics of storage for energy arbitrage and ancillary services?  What are the values that storage brings to the power system?  What regional strategies are being pursued?  Will storage be truly transformational, merely valuable, or highly overrated?   ISO Governance and Processes: Are They Adequate in an Increasingly Dynamic Market? Is Some Harmonization Needed? The RTO/ISOs have processes and powers that vary from one to another. The reasons for the variations are derived from historical circumstances.  Sections 205 and 206 of the Federal Power Act (“FPA”) establish the core substantive and procedural regulations governing the filing of rates, terms and conditions of wholesale power sales and transmission service in interstate commerce offered by public utilities subject to FERC jurisdiction. The governance rules of each RTO/ISO specify the internal procedures and stakeholder approvals necessary before the RTO staff are authorized to make such filings. As a result of different governance protocols, some markets are able to respond relatively quickly to changing economic and operating circumstances or perceived dysfunctions in market rules; other markets must navigate considerably more complex and time consuming internal stakeholder protocols before submitting a filing under Sections 205 and 206.  In some cases, stakeholder groups may be able to delay or effectively block proposed submissions.  At a time of rapid changes in market conditions and the substantial economic harms incurred by flawed or dysfunctional market rules, should FERC consider mandating a more consistent governance framework?  What are the conflicts in the RTO/ISO responsibilities to support efficient markets, preserve reliability, and respect the wishes of the various stakeholders? Should FERC reassess the weighted voting procedures and look at reforming and possibly streamlining the stakeholder process?   Warm regards,   Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School 617-496-6760 Hannah_Bruner@hks.harvard.edu       Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School 617-496-6760 Hannah_Bruner@hks.harvard.edu   REGISTRATION FORM HEPG SEVENTY-EIGHTH PLENARY SESSION TUESDAY AND WEDNESDAY, MARCH 24 – 25, 2015 RITZ-CARLTON HALF MOON BAY, CA TO: HARVARD ELECTRICITY POLICY GROUP John F. Kennedy School of Government FROM: Name Title Affiliation Address Phone E-mail ______YES, I will be able to attend the HEPG Plenary Session. ______ NO, I will not be able to attend the meeting. ______ I would like to send my designee: Name Title Address Phone E-mail ___________________________ ___________________________ ___________________________ ___________________________ ___________________________ ___________________________ HOTEL INFORMATION We have reserved a block of rooms at the Ritz-Carlton Half Moon Bay for the evenings of Monday, March 23 and Tuesday, March 24. Please arrange your reservation through Hannah Bruner in the Harvard Electricity Policy Group: Hannah_Bruner@hks.harvard.edu. The Ritz-Carlton is located at 1 Miramontes Point Road in Half Moon Bay, CA 94019. Registration deadline: February 20, 2015. To register for the session, please fax or e-mail this reply form to: Jo-Ann Mahoney, HEPG Program Director Fax: (617) 495-1635 Phone: (617) 495-1390 email to: jo-ann_mahoney@harvard.edu From: To: Cc: Subject: Date: Bob Stump Bruner, Hannah Beth L. Soliere Re: HEPG Spring 2015 Meeting Wednesday, January 21, 2015 11:12:40 AM Looking forward to it! See you then.  Bob Sent from my iPhone On Jan 21, 2015, at 11:03 AM, Bruner, Hannah wrote: Dear Chairmen and Commissioners,   On behalf of HEPG, I would like to invite you to participate in the next meeting of the Harvard Electricity Policy Group. This session is to be held in California on Tuesday, March 24 and Wednesday, March 25, 2015.  For your planning purposes, the meeting will convene on Tuesday morning at breakfast (8:30 am) and adjourn at noon on Wednesday.  The conference reception and dinner will take place on Tuesday evening.   Please expect to receive hotel and registration information in the next few days.   We hope your new year is off to great start and hope to see you in California!   Warm regards,     Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School 617-496-6760 Hannah_Bruner@hks.harvard.edu   From: To: Subject: Date: Bruner, Hannah Bruner, Hannah HEPG Spring 2015 Meeting Wednesday, January 21, 2015 11:03:26 AM Dear Chairmen and Commissioners,   On behalf of HEPG, I would like to invite you to participate in the next meeting of the Harvard Electricity Policy Group. This session is to be held in California on Tuesday, March 24 and Wednesday, March 25, 2015.  For your planning purposes, the meeting will convene on Tuesday morning at breakfast (8:30 am) and adjourn at noon on Wednesday.  The conference reception and dinner will take place on Tuesday evening.   Please expect to receive hotel and registration information in the next few days.   We hope your new year is off to great start and hope to see you in California!   Warm regards,     Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School 617-496-6760 Hannah_Bruner@hks.harvard.edu   From: To: Subject: Date: Bob Stump Beth L. Soliere hepg Tuesday, January 20, 2015 5:49:05 PM Susan says hepg is in march -Bob Stump Chair, Phoenix Opera 3120 West Carefree Highway, Suite 1-106 Phoenix, AZ 85086   Commissioner, Arizona Corporation Commission 1200 W. Washington Phoenix, AZ  85007 602-542-3935 From: To: Subject: Date: Bruner, Hannah Beth L. Soliere RE: Emailing: HEPG.NewOrleans.Stump Wednesday, January 14, 2015 8:39:40 AM Hi, Beth, Sure. The flight confirmation is fine. If you'll just email it to me, that would be great. Also, I received the receipts in the mail yesterday. Thank you for sending them. Best wishes, Hannah -----Original Message----From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Tuesday, January 13, 2015 2:51 PM To: Bruner, Hannah Subject: RE: Emailing: HEPG.NewOrleans.Stump Hi Hannah, Is the flight confirmation from the airline okay to send? -----Original Message----From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Tuesday, January 06, 2015 9:36 AM To: Beth L. Soliere Subject: RE: Emailing: HEPG.NewOrleans.Stump Hello, Beth, I hope you've had a  nice holiday. Thank you for sending back the reimbursement form. When convenient, please send the original receipts to  my attention at the following  address:          Hannah Bruner         HEPG         79 JFK St., Box 84         Cambridge, MA 02155 Thank you! Best wishes, Hannah -----Original Message----From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Monday, December 29, 2014 2:57 PM To: Bruner, Hannah Subject: Emailing: HEPG.NewOrleans.Stump   Your message is ready to be sent with the following file or link attachments: HEPG.NewOrleans.Stump Note: To protect against computer viruses, e-mail programs may prevent sending or receiving certain types of file attachments.  Check your e-mail security settings to determine how attachments are handled. From: To: Subject: Date: Bruner, Hannah Bob Stump RE: Reimbursement for Conference Travel Tuesday, January 06, 2015 10:01:55 AM Hello, Bob,  I had a wonderful Christmas--thank you. I hope you did as well. I'm sorry to hear work has been hectic. Hopefully, it has calmed down somewhat after the  holidays.  I look forward to reading your Faulkner paper when you have time to send it. Best  wishes, Hannah -----Original Message----From: Bob Stump [mailto:bstump@azcc.gov] Sent: Wednesday, December 24, 2014 12:43 AM To: Bruner, Hannah Subject: Re: Reimbursement for Conference Travel Hannah, I haven't forgotten my Faulkner-paper promise - all hell broke loose, work-wise, once I returned to Phoenix! I hope your Christmas is a great one, and talk with you soon. Bob Sent from my iPhone On Dec 10, 2014, at 9:00 AM, Bruner, Hannah > wrote: Dear Commissioner Stump, Thank you for your attendance and participation in HEPG’s December meeting. I hope you enjoyed your time in New Orleans and found the panels interesting. HEPG is happy to reimburse you for your travel expenses. However, to do so, we ask that you kindly complete and return the appropriate forms. Please find attached the Non-Employee Reimbursement form and the Missing Receipt Affidavit. Please let me know if you have any trouble viewing the attached documents. Per Harvard requirements, please send all original receipts by mail to the following address: Hannah Bruner HEPG 79 JFK St., Box 84 Cambridge, MA 02138 For lost receipts, please complete and return—preferably by email—the attached Missing Receipt Affidavit. If you have any questions or need assistance, please advise me. Thank you once again for your contribution to the success of HEPG’s December session. Warm regards, Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu From: To: Subject: Date: Bruner, Hannah Beth L. Soliere RE: Emailing: HEPG.NewOrleans.Stump Tuesday, January 06, 2015 9:37:05 AM Hello, Beth, I hope you've had a  nice holiday. Thank you for sending back the reimbursement form. When convenient, please send the original receipts to  my attention at the following  address:          Hannah Bruner         HEPG         79 JFK St., Box 84         Cambridge, MA 02155 Thank you! Best wishes, Hannah -----Original Message----From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Monday, December 29, 2014 2:57 PM To: Bruner, Hannah Subject: Emailing: HEPG.NewOrleans.Stump   Your message is ready to be sent with the following file or link attachments: HEPG.NewOrleans.Stump Note: To protect against computer viruses, e-mail programs may prevent sending or receiving certain types of file attachments.  Check your e-mail security settings to determine how attachments are handled. From: To: Subject: Date: Shannon Whiteaker Beth L. Soliere RE: Reimbursement for Conference Travel Monday, December 15, 2014 10:15:37 AM done   From: Beth L. Soliere Sent: Monday, December 15, 2014 10:15 AM To: Shannon Whiteaker Subject: FW: Reimbursement for Conference Travel   Will you try to print this?   From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Monday, December 15, 2014 10:09 AM To: Beth L. Soliere Subject: RE: Reimbursement for Conference Travel   Hi, Beth, Sure. I’ve attached the form in a different format. Please let me know if you are still having trouble opening it. Best wishes, Hannah   From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Monday, December 15, 2014 11:31 AM To: Bruner, Hannah Subject: RE: Reimbursement for Conference Travel   Hi Hannah,   For some reason I cannot open the travel claim form. Would you mind trying to resend it to me?   Thanks!   From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Wednesday, December 10, 2014 8:59 AM To: Bob Stump Cc: Beth L. Soliere Subject: Reimbursement for Conference Travel   Dear Commissioner Stump,   Thank you for your attendance and participation in HEPG’s December meeting. I hope you enjoyed your time in New Orleans and found the panels interesting.   HEPG is happy to reimburse you for your travel expenses. However, to do so, we ask that you kindly complete and return the appropriate forms.   Please find attached the Non-Employee Reimbursement form and the Missing Receipt Affidavit. Please let me know if you have any trouble viewing the attached documents.   Per Harvard requirements, please send all original receipts by mail to the following address:   Hannah Bruner HEPG 79 JFK St., Box 84 Cambridge, MA 02138   For lost receipts, please complete and return—preferably by email—the attached Missing Receipt Affidavit.   If you have any questions or need assistance, please advise me.   Thank you once again for your contribution to the success of HEPG’s December session.   Warm regards,     Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu   From: To: Subject: Date: Attachments: Bruner, Hannah Beth L. Soliere RE: Reimbursement for Conference Travel Monday, December 15, 2014 10:09:51 AM non-employee reimbursement.pdf Hi, Beth, Sure. I’ve attached the form in a different format. Please let me know if you are still having trouble opening it. Best wishes, Hannah   From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Monday, December 15, 2014 11:31 AM To: Bruner, Hannah Subject: RE: Reimbursement for Conference Travel   Hi Hannah,   For some reason I cannot open the travel claim form. Would you mind trying to resend it to me?   Thanks!   From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Wednesday, December 10, 2014 8:59 AM To: Bob Stump Cc: Beth L. Soliere Subject: Reimbursement for Conference Travel   Dear Commissioner Stump,   Thank you for your attendance and participation in HEPG’s December meeting. I hope you enjoyed your time in New Orleans and found the panels interesting.   HEPG is happy to reimburse you for your travel expenses. However, to do so, we ask that you kindly complete and return the appropriate forms.   Please find attached the Non-Employee Reimbursement form and the Missing Receipt Affidavit. Please let me know if you have any trouble viewing the attached documents.   Per Harvard requirements, please send all original receipts by mail to the following address:   Hannah Bruner HEPG 79 JFK St., Box 84 Cambridge, MA 02138   For lost receipts, please complete and return—preferably by email—the attached Missing Receipt Affidavit.   If you have any questions or need assistance, please advise me.   Thank you once again for your contribution to the success of HEPG’s December session.   Warm regards,     Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu   Ellil?l?l Il??wmizm?h,? . Harvard University on Em ployee Relm bu rsement Form University Financial Services - 1033 Massachusetts Ave, 2nd Floor Cambridge, MA 02138 Request Date: NR Number*: Reimbursee Name: Requisition Affiliation 0 Invited Guest Harvard Student OOther (Explain below) HUID (Affiliates):* Other Explanation US. Citizen orPermanent Resident QYes ONO FederaISponored Funds ?CiYes ONO Dates of Business Purpose: Provide detailed reasons and date ranges for expenditures. Travel and entertainment Expense(5) expenses require the person(s) and/or organization and location. ALL expenses must be itemized. #1 #2 #3 ALL EXPENSES MUST BE ITEMIZED INCLUDING EXPENSES LESS THAN $75 (A DETAILED ITEMIZED LIST FOR EXPENSES LESS THAN $75 CAN BE ATTACHED To THIS FORM) Description (date, details, etc) Air/Rail Lodging Bub/11229555 Other Total #1 #2 #3 Sub-Total expenses from page 2 Total Reimbursement rh Total amount under $75 itemized in Total Reimbursement I certify these are valid business expenses on behalf of Harvard University Reimbursee Signature:* Reimbursee Check Mailing Address:* Prepared By (Print): Phone You agree no unallowable costs, including undocumented expenses under $75, are being charged to Federal Funds as specified in 0MB Circulars A-21 and A-22. Approved By (Print): Phone TO EXPEDITE PAYMENT, PLEASE RETURN COMPLETED FORM AND REQUIRED DOCUMENTATION TO THE UNIT RESPONSIBLE FOR . . PROCESSING THE ELECTRONIC REQUEST *Requlred Field Elli Page 2 terms? Non Employee Relmbursement Form Reimbursee Name: Req?JiSition Additional Expenses Description (date details etc) Air/Rail Lodging Ground Business Other Total Trans Meals Sub-Total Reimbursement Line Distribution Business Purpose Amount Tub Org Object Fund Activity Sub Root *Required Field HINTS AND POLICY NOTES: Please refer to for complete policy. This completed form and required documentation must be returned to the local unit for processing. It? From: To: Subject: Date: Teresa Tenbrink Beth L. Soliere RE: Reimbursement for Conference Travel Wednesday, December 10, 2014 2:24:58 PM Contact IT.   Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   From: Beth L. Soliere Sent: Wednesday, December 10, 2014 2:12 PM To: Teresa Tenbrink Subject: RE: Reimbursement for Conference Travel   No, it must be my computer.  Uff.   From: Teresa Tenbrink Sent: Wednesday, December 10, 2014 2:07 PM To: Beth L. Soliere Subject: RE: Reimbursement for Conference Travel   No but try to open the ones that I attached.  Do they work now?   Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   From: Beth L. Soliere Sent: Wednesday, December 10, 2014 2:05 PM To: Teresa Tenbrink Subject: FW: Reimbursement for Conference Travel   Are you having trouble opening these attachments?   From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Wednesday, December 10, 2014 8:59 AM To: Bob Stump Cc: Beth L. Soliere Subject: Reimbursement for Conference Travel   Dear Commissioner Stump,   Thank you for your attendance and participation in HEPG’s December meeting. I hope you enjoyed your time in New Orleans and found the panels interesting.   HEPG is happy to reimburse you for your travel expenses. However, to do so, we ask that you kindly complete and return the appropriate forms.   Please find attached the Non-Employee Reimbursement form and the Missing Receipt Affidavit. Please let me know if you have any trouble viewing the attached documents.   Per Harvard requirements, please send all original receipts by mail to the following address:   Hannah Bruner HEPG 79 JFK St., Box 84 Cambridge, MA 02138   For lost receipts, please complete and return—preferably by email—the attached Missing Receipt Affidavit.   If you have any questions or need assistance, please advise me.   Thank you once again for your contribution to the success of HEPG’s December session.   Warm regards,     Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu   From: To: Cc: Subject: Date: Attachments: Bruner, Hannah Bob Stump Beth L. Soliere Reimbursement for Conference Travel Wednesday, December 10, 2014 9:00:13 AM MRA.PDF Non-Employee Reimbursement Form.pdf Dear Commissioner Stump,   Thank you for your attendance and participation in HEPG’s December meeting. I hope you enjoyed your time in New Orleans and found the panels interesting.   HEPG is happy to reimburse you for your travel expenses. However, to do so, we ask that you kindly complete and return the appropriate forms.   Please find attached the Non-Employee Reimbursement form and the Missing Receipt Affidavit. Please let me know if you have any trouble viewing the attached documents.   Per Harvard requirements, please send all original receipts by mail to the following address:   Hannah Bruner HEPG 79 JFK St., Box 84 Cambridge, MA 02138   For lost receipts, please complete and return—preferably by email—the attached Missing Receipt Affidavit.   If you have any questions or need assistance, please advise me.   Thank you once again for your contribution to the success of HEPG’s December session.   Warm regards,     Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu   HARVARD UNIVERSITY MISSING RECEIPT AFFIDAVIT Missing Receipt Affidavits lacking the required information or documentation will be returned to the authorized signer. Airline Tickets Attached is a copy of the itinerary invoice and proof of payment (i.e., credit card statement, cancelled check) Hotel Folio Attached is a copy of the hotel folio and proof of payment (i.e., credit card statement) -ORI certify that I have contacted the hotel and was unable to obtain a copy of the hotel folio. Please reimburse me based on the following information and proof of payment: Date # of nights Hotel/City Daily Rate Total Car Rental Agreement Attached is a copy of the car rental agreement and proof of payment (i.e., credit card statement) -ORI certify that I have contacted the rental car agency and was unable to obtain a copy of the car rental agreement Please reimburse me based on the following information and proof of payment: Dates Rental Company Car Class* # of Days Total *C=Compact, M=Mid-size, F= Full-size Date B, L, D* Meals (list each meal separately) Restaurant/City # of People** Total *B=Breakfast, L=Lunch, D=Dinner (**Name of attendees and business purpose is required on Expense Report or Pcard Settlement System) Miscellaneous For PCard transactions include a copy of the sweep report from the Pcard Settlement System or a copy of the credit card statement. Date Description (in detail) Total I, the undersigned, certify (a) that each expense described above, reported on Web Reimbursement Report ,or on the Pcard Settlement System Report was/were lost or not obtained, and (b) that number these expenses have not yet nor will again be submitted to Harvard University or any other organization for reimbursement or tax purposes. Signature of Payee/Card holder Authorized Signature REQUIRED REQUIRED Date Date ___ From: To: Subject: Date: Attachments: Mahoney, Jo-Ann Beth L. Soliere FW: agenda Tuesday, December 02, 2014 3:16:18 PM HEPG_12_14_DraftAgenda_speakers_.docx From: Mahoney, Jo-Ann Sent: Tuesday, December 02, 2014 4:15 PM To: julie.simon@ferc.gov Subject: FW: agenda From: Bruner, Hannah Sent: Monday, December 01, 2014 1:08 PM To: Mahoney, Jo-Ann Subject: agenda     Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu   HARVARD ELECTRICITY POLICY GROUP HARVARD ELECTRICITY POLICY GROUP SEVENTY-SEVENTH PLENARY SESSION Windsor Court Hotel New Orleans, LA THURSDAY AND FRIDAY, DECEMBER 4 - 5, 2014 AGENDA Thursday, December 4 8:30 am Breakfast and Informal Discussion 9:00 am Session One. Environmental Dispatch: Now? Or Never? The notion of using environmental criteria to dispatch power plants has periodically arisen as an approach to reduce emissions. The theory seems simple to some: namely, that plants are to be dispatched on an emissions merit order basis—least emitting sources first—subject, of course, to security constraints. While the idea may be simple, actual implementation would raise many questions. What would environmental protocols look like? How does one balance between economic and environmental merit orders? How do incremental costs for out-of-economic merit order get allocated? How might such a system fit into Section 111(d) SIP’s? What impact would environmental dispatch have on LMPs and FTR markets? Would the standard market design collapse or adapt? Are all plants capable of operating in a fashion that would allow for emissions based dispatch, and if not, how should that be dealt with? How do multi-state system operators dispatch in an environmental merit order when various states may have different, if not conflicting, compliance programs? How would emissions trading be altered by environmental dispatch? In short, how would such a system work, and can it be done on a reasonably efficient basis? Moderator: Anne Hoskins, Maryland Public Service Commission George Angelidis, California Independent System Operator William Hogan, Harvard Kennedy School Adam Keech, PJM Interconnection Jonathan Schrag, New York University School of Law HEPG Agenda, December 4-5, 2014 Thursday, December 4 (cont’d) 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Lunch 1:15 pm Session Two. Technology and Resource Choice: What Value Diversity? Natural gas has clearly become the “fuel of choice” for new generation in the United States. That “choice,” of course, was not dictated by policy but rather by the marketplace. The competitors of gas—primarily coal, nuclear, and renewables—have either been more expensive, less reliable, or environmentally riskier or perceived to have some combination of those market disadvantages. The result has been what some have characterized as a market driven “rush to gas.” Some would contend that resource decisions need to better take into account the benefits of diversity in resources. Prior to the emergence of competition, vertically integrated utilities, as well as regulators, through integrated planning processes could try to optimize such long and short term considerations. Is such an effort possible in a competitive market? Is it needed, or, over time will market forces balance things out? Renewables in many jurisdictions have their own set aside market: renewable portfolio standards. Nuclear and coal have no such set aside haven from the market. Should RTO planning processes be required to explicitly address portfolio diversity? If so, what criteria should be used in forgoing currently knowable price information in favor of longer-term insulation from volatility? What reasonable risks should a merchant generator be expected to take when it opts for a resource that is out of the market at present? How would the costs of any above current market plans be allocated? Are the prices for “out of market” resources actually brought back into the market by virtue of having fuel on site or other reliability/systems operations perspectives? What would such a planning process do to the competitive nature of the marketplace? Moderator: Mary Ellen Paravalos, National Grid William Allen, American Electric Power Joseph Dominguez, Exelon Corporation Larry Makovich, IHS Richard O'Neill, Federal Energy Regulatory Commission 2:45 pm Coffee Break 3:00 pm Discussion 4:15 pm Adjourn 6:00 pm Reception and Dinner Calcasieu 930 Tchoupitoulas Street, New Orleans Transportation will be provided from the Windsor Court at 5:45 pm. HEPG Agenda, December 4-5, 2014 Friday, December 5 8:30 am Breakfast and Informal Discussion 9:00 am Session Three. Resource Adequacy Reconsidered: Mandates and Markets Assuring resource adequacy has been an ongoing challenge since the transition to competition began. A number of measures have been taken to try to address the matter. These include the development of capacity markets and demand response programs. Events and continuing reform initiatives challenge both the effectiveness and costs of these programs. Criticisms of capacity markets continue, and the court decisions on Order 745 raise new questions about how to address demand response. An addition to resource adequacy concerns is fuel supply and pipeline capacity. While this issue has been of particular concern in New England, where pipeline capacity is highly constrained at certain times of the year, it has the potential, given the country’s increased reliance on natural gas, to become a problem elsewhere as well. How far can we rely on markets to assure resource adequacy? What mandates are required? Does the mandate of capacity markets mix with the market model of generation supply? What alternatives are available to supply and demand options organized in mandatory capacity markets? Do mandates support or replace market solutions? Moderator: Christi Nicolay, Macquarie Energy Bruce Edelston, Energy Policy Group Susan Kelly, American Public Power Association Donald Santa, INGAA John Shelk, Electric Power Supply Association 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Adjourn From: To: Subject: Date: Attachments: Bob Stump Beth L. Soliere Fwd: HEPG: Reading from Bruce Edelston Monday, December 01, 2014 12:34:21 PM Ensuring Adequate Power Supplies 6-3-14 for EMRF.pdf ATT00001..htm For printing please  Sent from my iPhone Begin forwarded message: From: "Mahoney, Jo-Ann" To: "Mahoney, Jo-Ann" Cc: "Bruner, Hannah" Subject: HEPG: Reading from Bruce Edelston We look forward to seeing you this week in New Orleans.  Bruce Edelston has provided the study on which his presentation will be based. Best, Jo-Ann From: To: Cc: Subject: Date: Attachments: Mahoney, Jo-Ann Mahoney, Jo-Ann Bruner, Hannah HEPG: Reading from Bruce Edelston Monday, December 01, 2014 12:33:17 PM Ensuring Adequate Power Supplies 6-3-14 for EMRF.pdf We look forward to seeing you this week in New Orleans.  Bruce Edelston has provided the study on which his presentation will be based.   Best, Jo-Ann   ENSURING ADEQUATE POWER SUPPLIES FOR TOMORROW’S ELECTRICITY NEEDS prepared by Mathew J. Morey Laurence D. Kirsch B. Kelly Eakin Robert J. Camfield Christensen Associates Energy Consulting LLC prepared for June 3, 2014 Christensen Associates Energy Consulting, LLC 800 University Bay Drive, Suite 400 Madison, WI 53705-2299 Voice 608.231.2266 Fax 608.231.2108 ©Copyright 2014 This report is protected by copyright. Any publication in any form without the express written consent of Electric Markets Research Foundation is prohibited. Electric Markets Research Foundation Christensen Associates Energy Consulting conducted this study for the Electric Markets Research Foundation (EMRF). EMRF was established in 2012 as a mechanism to fund credible expert research on the experience in the United States with alternative electric utility market structures – those broadly characterized as the traditional regulated model where utilities have an obligation to serve all customers in a defined service area and in return receive the opportunity to earn a fair return on investments, and the centralized market model where generation is bid in to a central market to set prices and customers generally have a choice of electric supplier. During the first few years of restructured markets, numerous studies were done looking at how these two types of electric markets were operating and the results were mixed. But since those early studies, limited research has been done regarding how centralized markets and traditionally regulated utilities have fared. The Electric Markets Research Foundation has been formed to fund studies by academics and other experts on electric market issues of critical importance. Christensen Associates Energy Consulting CA Energy Consulting is a wholly owned subsidiary of Laurits R. Christensen Associates, Inc., whose multi-disciplinary team of economists, engineers, and market research specialists has been serving the electric power industry (as well as other industries) since 1976. CA Energy Consulting’s focus on energy markets covers a broad range of technical and regulatory policy issues concerning wholesale and retail electricity market restructuring, market design, power supply, asset evaluation, transmission pricing, market power, retail and wholesale rate design, and customer response to price signals. TABLE OF CONTENTS Contents EXECUTIVE SUMMARY ............................................................................................................ I 1. THE RESOURCE ADEQUACY CHALLENGE ........................................................................... 1 2. SECURITY, ADEQUACY, AND RELIABILITY .......................................................................... 2 3. MARKET STRUCTURES ...................................................................................................... 3 3.1. Overview of Electricity Market Structures.................................................................... 3 3.1.1. Traditional Markets........................................................................................ 4 3.1.2. Restructured Markets .................................................................................... 5 3.1.3. Overview of Prevalent Market Types in Each State....................................... 7 3.1.4. Similarities and Differences Among the Market Types ................................. 8 3.2. Capacity Cost Recovery Mechanisms ......................................................................... 10 3.2.1. Cost Recovery Under a Purely Market Scheme ........................................... 11 3.2.2. Cost Recovery With a Capacity Requirement Scheme ................................ 13 4. DETERMINATION OF CAPACITY REQUIREMENTS............................................................. 15 4.1. Regulatory Context ..................................................................................................... 16 4.1.1. North American Electric Reliability Corporation Standards ........................ 16 4.1.2. Regional Reliability Entities Standards ........................................................ 17 4.1.3. Federal Energy Regulatory Commission Requirements .............................. 19 4.1.4. State Requirements ..................................................................................... 20 4.2. Requirements of the Regional Transmission Operators............................................. 20 4.2.1. Methods for Determining Capacity Requirements...................................... 20 4.2.2. Determination of Capacity Prices ................................................................ 23 4.2.3. Market Power Mitigation............................................................................. 27 4.2.4. Strengths and Weaknesses of the Price Determination Methods .............. 28 4.3. Traditionally Regulated Regions ................................................................................. 29 5. RESOURCE OUTCOMES .................................................................................................. 30 5.1. Reliability..................................................................................................................... 30 5.2. Resource Additions and Reserves ............................................................................... 32 5.2.1. Overview of U.S. Capacity Resources .......................................................... 33 5.2.2. Traditionally Regulated Regions with Vertically Integrated Utilities ........... 34 5.2.3. Centralized Markets of Regional Transmission Operators .......................... 36 5.2.4. Summary of Findings.................................................................................... 39 5.3. Resource Mix............................................................................................................... 39 5.3.1. Overview of the U.S. Resource Capacity Mix............................................... 40 5.3.2. Overview of Regional Capacity Resources ................................................... 41 5.3.3. Renewable Energy Resources ...................................................................... 41 5.3.4. Demand-Side Resources .............................................................................. 44 5.3.5. Summary ...................................................................................................... 47 5.4. 5.5. 5.6. 5.7. Net Revenue Analysis.................................................................................................. 50 Price Trends ................................................................................................................ 52 Cost Trends ................................................................................................................. 53 Observations ............................................................................................................... 56 5.7.1. Relationships of Market Design to Resource Adequacy .............................. 57 5.7.2. Assessment of Resource Diversity Effects ................................................... 60 5.7.3. Long-Term Contracting and Generation Investment .................................. 60 5.7.4. Natural Gas Deliverability ............................................................................ 60 5.7.5. Plant Retirements ........................................................................................ 62 5.7.6. Reliability Issues Arising from Intermittent Resources ................................ 63 6. PROSPECTIVE RELIABILITY IMPACTS OF EVOLVING TECHNOLOGY ................................... 64 6.1. Increases in Resource Capacities ................................................................................ 64 6.2. Improvements in Power System Control .................................................................... 64 6.3. Complications to Power System Control .................................................................... 64 7. DIRECTIONS FOR FUTURE REFORM OF METHODS FOR ASSURING ADEQUATE CAPACITY . 65 7.1. Reforms in Defining the Capacity Mandate ................................................................ 65 7.1.1. Reformed Pricing of Operating Reserves ..................................................... 65 7.1.2. Capacity Compensation Based on Actual Resource Availability .................. 67 7.1.3. Recognition of the Diversity of Capacity Values .......................................... 69 7.2. Reforms in Methods for Meeting Capacity Mandates ............................................... 74 7.2.1. Resource Obligations Borne by Distribution Service Providers ................... 74 7.2.2. Capacity Options .......................................................................................... 76 7.2.3. Treatment of Self-Supply Relative to Centralized Capacity Markets .......... 76 7.2.4. Reform of LMP Pricing ................................................................................. 79 8. CONCLUSIONS ............................................................................................................... 80 ENSURING ADEQUATE POWER SUPPLIES FOR TOMORROW’S ELECTRICITY NEEDS EXECUTIVE SUMMARY The Resource Adequacy Challenge The Electric Markets Research Foundation (Foundation) critically examines key issues facing the country’s electricity sector arising from industry restructuring that has taken place over the past two decades. The Foundation commissioned Christensen Associates Energy Consulting to examine the ability of the U.S. electric power industry to build and maintain sufficient electric generating capacity to meet the country’s present and future needs. While many regions of the country have undertaken restructuring of both retail and wholesale electricity markets, others have not, so that the U.S. electricity sector now serves consumers under two distinct market models. These models have different impacts upon the development of power facilities and the production and delivery of power. One market model relies on competitive bidding to establish market prices for wholesale power delivered to end-use customers by retail suppliers who may or may not own generation, transmission, and distribution facilities. Regional transmission organizations (RTOs) or independent system operators (ISOs) operate the competitive wholesale markets in restructured market regions. The other market model relies on traditional regulation of vertically integrated utilities that provide generation, transmission, and distribution services to end-use customers at prices approved by state regulatory commissions. Within the restructured market regions, many but not all states have adopted retail competition, in which multiple retail suppliers of electric energy and related services compete to serve end-users. The first report published by the Foundation, entitled Evolution of the Electric Industry Structure in the U.S. and Resulting Issues, discusses in significant detail the historical transition to today’s dual market system and the industry’s current status.1 Whether the electricity sector is able to continue to develop and maintain sufficient resources to “keep the lights on” now and in the future, referred to as resource adequacy, has emerged over the past several years as perhaps the greatest challenge facing the electric power industry. Potentially serious resource adequacy problems were laid bare by the recent “polar vortex” of January and February 2014, when record cold temperatures across most of the eastern and Midwestern United States had the industry scrambling to keep up with the demand for electricity. While the industry managed to avoid blackouts, a general consensus has emerged that the industry came perilously close to exceeding its limits to maintain electric system 1 Navigant Consulting, Inc., Evolution of the Electric Industry Structure in the U.S. and Resulting Issues, prepared for Electric Markets Research Foundation, October 12, 2013, available at www.emrf.net. i reliability. Maintaining reliability during this period meant that many electricity consumers in some parts of the country paid unprecedented high prices for electricity. The nation’s ability to cope with a future “polar vortex” will be compromised by the slated retirements over the next few years of many of the generating plants called upon to keep the lights on during this last “polar vortex.” American Electric Power Company (AEP) CEO Nicholas Akins, in testimony before the Senate Energy and Natural resources Committee in April, pointed to January's deep freeze as a warning signal: A month ago, I made headlines when I said 89 percent of the generation that AEP will be retiring in 2015 was called upon to meet electricity demand in January. That is a fact… The weather events experienced this winter provided an early warning about serious issues with electric supply and reliability… This country did not just dodge a bullet -- we dodged a cannon ball.2 Akins told Congress that the problem needs to be fixed quickly. He asserted that the capacity markets in restructured market regions are “not functioning as intended,” and are failing to attract investment capital and to send price signals to retain existing generation in order to maintain a mix of energy resources necessary to ensure grid reliability. According to Akins, “[t]he [restructured] competitive wholesale markets are not currently providing the structure necessary to maintain that reliability and do not currently provide the proper economic signals to foster new power plant investment for the future.”3 Instead the electric power industry has become increasingly reliant on natural gas, particularly in the restructured wholesale markets. Recent downward trends in wholesale market prices and compliance with environmental regulations are increasingly rendering base load (coal and nuclear) power sources uneconomic. For example, AEP is slated to retire more than 6,500 megawatts of coal-fired generation – most of it by mid-2015 – and does not plan to add new capacity in the near term. Reliability is not the only issue. Shortages of power during the polar vortex created significant spikes in the price of wholesale power, which has quickly morphed into a political issue. PPL Corporation, a utility serving customers in central Pennsylvania, saw wholesale (spot market) prices briefly exceed $2,000 per megawatt hour compared to $40 per megawatt hour on a normal day.4 In Texas, where the grid is managed by the Electric Reliability Council of Texas (ERCOT), prices reached wholesale market price cap of $5,000 per megawatt hour for the first 2 Testimony of Nicholas K. Akins, Chairman, President and Chief Executive Officer, American Electric Power, Senate Energy and Natural Resources Committee Hearing on “Keeping the Lights On - Are We Doing Enough to Ensure the Reliability and Security of the U.S. Electric Grid?”, April 10, 2014, pp. 2-4. 3 Id., p. 5. 4 G.J. Millman, “PPL’s Risk Management Tested by Polar Vortex,” Wall Street Journal, April 17, 2014, obtained at http://blogs.wsj.com/riskandcompliance/2014/04/17/ppls-risk-management-tested-by-polar-vortex/. ii time ever on January 6th, partly due to plant outages.5 Few retail customers experienced these high prices at the time because retail electricity rates typically do not fluctuate with changes in wholesale spot market prices. But those electricity customers whose bills do reflect hourly wholesale prices, including many in New York and New England, experienced significant price shock. For example, based on an estimated 27% jump in wholesale electricity prices in January, the New York Public Service Commission authorized National Grid serving northern New York State to recover January’s higher wholesale power costs in retail rates over a four month period. U.S. Senator Charles Schumer has called for an FTC investigation into these price spikes in northern New York. Most of the concerns regarding resource adequacy have arisen in the context of restructured wholesale and retail electric markets. The restructured markets are still trying to prove the workability of their model for assuring resource adequacy. By contrast, capacity reserves have been successfully maintained in almost all regions that have not restructured and that continue to rely on franchised electric utilities that take direct responsibility for resource adequacy under an obligation to serve. The success of traditionally regulated electric markets to maintain resource adequacy has not been achieved without controversy, however, as questions have sometimes arisen about how those reserve requirements were satisfied and at what cost. Nevertheless, resource adequacy has not been seen as a major issue in traditionally regulated markets in the past. Additional Concerns in Restructured Markets While the polar vortex provided a warning signal to the nation, it is not just extreme weather and attendant wholesale power price spikes that is creating concern about resource adequacy in the restructured markets. Additional concerns that have arisen in restructured markets include the following:  Reserve margins have declined in almost all regions of the country over the past decade. However, the decline in restructured market regions has been more pronounced than in other regions, and has become the center of increasing concern, highlighted by the recent polar vortex experience. Furthermore, projected capacity retirements – primarily due to environmental restrictions - exceed planned additions for the foreseeable future.  Low average wholesale market electricity prices in restructured markets in recent years have made it more difficult for owners to recover plant operating costs and have thereby induced the retirement of two carbon-free nuclear power plants. Additional nuclear plants are in danger of closing for similar reasons. 5 K. Kelly-Detwiler, “Volatility In Early January Power Markets: The Vexing Polar Vortex,” January 16, 2014, obtained at http://www.forbes.com/sites/peterdetwiler/2014/01/16/volatility-in-early-january-power-marketsthe-vexing-polar-vortex/. iii  With natural gas as the preferred fuel source for the majority of newly installed or planned generation capacity in restructured markets, the polar vortex has also focused attention on long-term gas availability and pricing, including the availability of firm gas pipeline transportation. Is there over-reliance on natural gas? What are the economic security and consumer price volatility concerns that result from heavy reliance on natural gas?  Increased reliance on intermittent resources that are not always available when needed, such as solar and wind, raise additional concerns for maintaining resource adequacy.  Subsidies for particular generation technologies, such as the production tax credits for wind energy, tend to distort competitive market outcomes.  A host of public policies interfere with the operation of restructured electricity markets. Consequently, these markets provide only limited support for investment in generation and other resources. o The restructured markets cap prices in order to limit consumers’ exposure to price volatility. With prices capped, the market-clearing price paid to resources under capacity shortage conditions cannot reach levels high enough to encourage the provision of sufficient additional resources or induce sufficient load reductions. . o For the years 2005 through 2012, the RTOs’ analyses of revenue sufficiency indicate that net revenues were generally insufficient to allow recovery of the levelized capital costs of generation investment. Thus, on a levelized basis, the RTOs’ markets did not present an attractive enough opportunity to encourage sufficient investment in needed generation. o Some RTOs have implemented a market-like approach to capacity adequacy through the institution of centralized capacity markets that provide cost recovery assurance at most three years into the future. This short timeframe gives a very limited incentive for investments in capital-intensive generators with lives of thirty years or more. o Restructured markets do not provide market participants with mechanisms to arrange the long-term price hedges that can be critical to investment in longterm capacity. o Restructured market rules have been subject to frequent revision, thus creating uncertainty about their durability and adding to investment uncertainty. The consequences of these realities have been supplier bankruptcies and disincentives for arranging long-term supplies. There is reason to be concerned that, as a nation, we are paying insufficient attention to the issue of resource adequacy, particularly in restructured markets. While the obligation to serve coupled with integrated resource planning have enabled traditionally regulated markets to maintain sufficient planning reserves to meet current and future needs, levels of planning iv reserves in restructured markets have by and large been left to market forces. As these restructured markets have found that market prices have not always provided sufficient incentives to maintain required levels of reserves, they have attempted numerous market adjustments, including the establishment of separate capacity markets, to add additional resources. It does not appear that these efforts have been successful to date. A key finding of this report is that problems of restructured markets with securing adequate resources stems from their seeking a market solution to a problem for which there is not a market solution within existing political and institutional frameworks. Because of the shortcomings of market-based approaches, non-market (i.e., regulatory) mechanisms must be part of the overall approach to ensuring long-term resource adequacy. Long-term contracts and self-build options for load-serving entities (LSEs) must be encouraged to ensure an adequate resource mix. Traditional Versus Restructured Markets About a third of the U.S. population obtains electric power service based on traditional institutional arrangements. Under these arrangements, power is provided to consumers by vertically integrated utilities that own generation, have exclusive retail franchises, and trade wholesale power through bilateral contracts. Retail prices are regulated by state public service commissions. About two-thirds of the U.S. population obtains electricity through electric markets that have been restructured at the wholesale level. In these markets, generating capacity owned by utilities and independent third parties compete to sell generation into a centralized wholesale market as well through bilateral trades, with the lowest-cost resources that can reliably serve demand being chosen on a real-time basis. In some states within these restructured markets, retail customers may choose their electric supplier among competing entities that may be utilities or third-party competitive retail suppliers. Both traditional and restructured markets require mechanisms for assuring resource adequacy. In all markets other than Texas, LSEs have an obligation to procure capacity that is sufficient to serve their own retail load and cover reserves.6 In traditional markets, utilities build and own their own generating units or do so jointly with other utilities, develop long-term purchase arrangements with independent power producers, or procure short- and long-term resources under negotiated bilateral power purchase agreements with entities that have surplus resources. Utilities in these markets recover the costs of procuring these resources by charging rates that are determined by their costs of service. In restructured markets, utilities sometimes procure capacity resources in much the same fashion as in traditionally regulated regions. However, in restructured markets, utilities are 6 In Texas, retail energy providers (REPs) serve retail electric consumers without bearing a requirement to secure capacity sufficient to meet their load. v typically either allowed – or in some cases required – to trade through centralized short-term capacity markets operated by Regional Transmission Operators (RTOs). In states with retail access, regulators have often discouraged retail LSEs from owning their own generating resources, sometimes even barring LSEs from engaging in long-term contracts to hedge against short-term price fluctuations. While traditionally regulated electricity markets have regulatory issues, such as sometimes contentious proceedings to determine whether investments have been prudently incurred, these markets continue to meet resource adequacy requirements under the supervision of state regulators. The restructured markets, by contrast, are still trying to prove the workability of their model for assuring resource adequacy. Thus far, the RTOs have maintained adequate capacity. Nonetheless, some RTOs may or will soon be operating with historically low planning reserves under peak period conditions, particularly given planned retirements. It is unclear to what extent centralized capacity markets will assure reserve margins in restructured RTO markets, especially because the restructured states continue to play a significant role in determining capacity requirements for LSEs and mandating investments in renewable resource capacity. And some states are attempting to mandate additional investment in traditional resources outside RTO capacity markets as well.7 The current debate on resource adequacy arises primarily from questions about how to make the RTOs’ resource adequacy models work. The fundamental problem is that the RTOs seek a market solution for a problem that does not have a market solution because a suite of public policies require that capacity resources meet several non-market goals. These non-market goals include:  Electricity is vital to the national economy and shortages and price spikes are not tolerated by policymakers, regulators, and customers.  To protect customers from excessive price volatility, prices offered by generators in restructured markets are capped below levels that are needed to clear the market during peak load periods when capacity is scarce. Consequently, generators that serve load at peak are not able to obtain revenues sufficient to cover all of their costs, causing a “missing money” problem that dampens incentives for investment in new capacity.  The portfolio of capacity resources must include certain types of preferred resources – notably renewable resources and demand-side resources – that may be costly relative to conventional resources. 7 See New Jersey Board of Public Utilities and New Jersey Division of Rate Counsel, Petitioners, in Case No. 114245 v. Federal Energy Regulatory Commission, Respondent; and Maryland Public Service Commission, Petitioner, in Case No. 11-4405 v. Federal Energy Regulatory Commission, Respondent. The United States Court of Appeals for the 3rd Circuit in February 2014 denied requests of both New Jersey and Maryland commissions, as well as others who joined in the appeal for review of FERC’s earlier order denying rehearing of its 2011 orders pertaining to the PJM capacity market that eliminated the exemption from capacity market mitigation rules for resources built pursuant to a state mandate. vi  Different customers have different willingness to pay for different levels of bulk system reliability, but only one level of reliability can be maintained. Thus, reliability must be maintained at levels that exceed many customers’ willingness to pay for reliability. Because of these and other problems, the RTOs are continually reforming their capacity markets, sometimes in major ways, often through contentious proceedings, as they search for a market solution that cannot exist. Some RTOs have attempted to implement a market solution through the institution of short-term centralized capacity markets; but these markets have the key deficiency of going at most three years into the future, which cannot provide incentives for long-term capital-intensive generation investments with lives of thirty years or more. Resource Mix The mix of capacity resources can have major impacts on power system reliability, for several reasons. First, supplies of particular resources can become constrained due to weather conditions, transportation bottlenecks, or production problems; so over-reliance upon a single resource technology can have adverse reliability or cost impacts. Second, demand-side capacity resources are an innovation that is not entirely out of the testing stage: in the long run, such resources may or may not prove to be as reliable as traditional supply-side resources. Third, intermittent renewable resources (i.e., wind and solar) pose new challenges for maintaining power system security; and these challenges will grow disproportionately quickly as the market share of these resources grows. About 23,000 MW of coal-fired generating capacity retired between 2005 and 2013, and another 37,300 MW is expected to retire over the next decade, mostly during the next four years.8 Many of these retirements are in RTO regions. Meanwhile, in nearly every RTO region, gas-fired generation capacity has at least doubled over the past decade. Wind capacity has increased from almost nothing in 2000 to approximately 6% of total U.S. generating capacity today. The strong trend throughout the U.S. is toward natural gas capacity, in both restructured and traditionally regulated regions, though traditionally regulated regions have retained more fuel diversity. The differences between restructured and traditionally regulated regions in the change in resource mix seem to rise primarily from state requirements for renewable energy, plus the particular locational advantages of wind and solar resources. Resource Profitability To assess the market incentives for capacity investments, several RTOs estimate the net revenues (i.e., profits) that would have been earned in their markets by combustion turbines and combined cycle generators. For each of the years 2005 through 2012, net revenues on an 8 SourceWatch, Table 2, http://www.sourcewatch.org/index.php/Coal_plant_retirements. vii RTO-wide basis were generally insufficient to cover the levelized costs of these generators, though they were sufficient in ERCOT and New York in a few years and were sufficient in several subregions of the RTOs in some years. Because there was some need for new resource capacity during the boom years of 2005-2007, the insufficiency of net revenues implies a general failure of the RTOs’ markets to signal capacity shortages in these years. The failure has led to a general decline in RTO planning reserves in recent years and, particularly in light of the polar vortex experience this past winter, a rising concern that restructured markets may need to do more to address the resource adequacy issue. To encourage generation investment and delay generation retirements, the RTOs’ centralized capacity markets were created to provide resource owners with steady income streams. Nonetheless, their capacity market prices have been volatile over the past decade; so the centralized capacity markets have provided rather volatile income streams that create financial risks for investors in new generating plants. The investment problem is particularly acute because of the nature of electricity demand. Customer demand has a profile that includes baseline needs during normal weather conditions and usage, and higher peak demands during particularly cold or hot weather (depending on the region). A mix of generating technologies satisfies this range in electricity demand at least cost. The generators that serve demand only during peak load hours may be needed to run only a few days or even a few hours each year. Although such peaker plants have relatively low capital costs, they nonetheless need extremely high prices during those few days or hours to earn revenues sufficient to cover both the variable and fixed costs, including a return on their investment in capacity. Inconsistent with this need, however, the restructured markets have caps on prices generators can offer, thus precluding market prices from reaching levels high enough to provide the needed revenue for the peaker plants during those few hours when they are needed. This “missing money” problem extends beyond peaker plants to all other plant types, including baseload plants. The restructured markets’ capacity market mechanisms are intended to make up for the “missing money” and provide sufficient incentives for investment in both base load and peaking generation – so far with limited success. Key Findings of the Report The U.S. electric power industry has a 100-year history of providing capacity resources that have been adequate under all but the most extreme conditions. The main contributor to this favorable outcome has been a set of power industry business practices that require resources to exceed peak loads according to certain engineering-based analyses or rules of thumb. These industry practices have been supplemented and strengthened by various state proceedings such as integrated resource planning. While traditionally regulated electricity markets have issues such as contentious prudence determinations, these markets continue to meet resource adequacy requirements under the supervision of state regulators. viii The current debate on resource adequacy arises primarily from questions about how to make the restructured market model work. These questions arise from the following fundamental causes:  RTOs’ short-term centralized capacity markets do not provide incentives for long-term resource investments. These markets were designed to improve the short-term commitment and dispatch of power system resources; and for this short-term purpose, they have been very successful. But these RTO markets, being short-term markets, do not and cannot address long-term capacity needs.  The political process will not allow peak-period demand pricing that is consistent with a market solution. Specifically, the RTOs’ energy and ancillary services prices are capped by regulators; and on the rare occasions when non-price rationing (e.g., rolling blackouts) occurs due to a capacity shortfall, that rationing does not tend to discriminate between those consumers and retail suppliers who arrange adequate supplies and those who do not. These fundamental causes imply that the resource adequacy problem does not lend itself to a market solution. The RTOs, as they struggle to fit a square peg into a round hole, must therefore continually reform their capacity markets, sometimes in major ways, always through contentious proceedings, as they search for a market solution that cannot exist under existing political and regulatory frameworks. While a well-functioning market attracts participation because that market provides trades on terms that are comparable to or better than those available through other venues, the restructured markets’ centralized capacity markets tend to be mandatory. There are few places in the American economy wherein one can find a free market in which participation is mandatory. The traditionally regulated markets avoid all the foregoing problems by simply not attempting a market solution, except to the extent that they have competitive bidding procedures to meet identified capacity needs. There are additional matters that should be, and indeed already are, of great concern to policymakers and all stakeholders in the electric power industry:  The reliability of some portions of the power system has been challenged by a lack of fuel diversity in new generation development. The cold winter of 2013-2014 (the “polar vortex”) and the accompanying gas price spikes and gas delivery issues highlight the perils of over-reliance on any one fuel.  Gas-electric coordination has become increasingly important as we rely more on natural gas. Questions arise as to whether generation can be counted as firm capacity if it does not have firm gas pipeline transportation contracts. Again, the polar vortex was a demonstration of the possible implications of insufficient firm gas transportation.  The planned retirement of coal plants (for both economic and environmental reasons), and the actual and potential retirements of nuclear plants for economic reasons, will exacerbate the resource adequacy problem in some RTOs, creating significant reliability concerns. ix  There is reasonable concern about the capacity value of demand-side resources. It is risky to over-rely on these resources until they have been thoroughly tested by experience.  There is reasonable concern about the capacity value of intermittent resources, and about the power system control and security problems raised by their intermittency. There have been many proposals made to reform capacity markets or to design new methods to ensure resource adequacy in the restructured markets, but most of these proposals assume that tweaks to the restructured market model will be sufficient. A more comprehensive solution is necessary, however. For example, the restructured markets could be designed so that capacity is procured in ways similar to those used in traditional regulated markets: set capacity requirements according to engineering criteria; impose high penalties on those LSEs who fail to meet their requirements; and offer a centralized market for those parties who find the centralized market’s terms attractive. Generation could be procured through competitive solicitation as it is done successfully in some traditionally regulated markets as well as in some restructured markets. And RTOs could continue to operate energy markets in the same way as they do today. Our nation needs to continually strive for better regulatory and market rules that ensure resource adequacy at reasonable cost to consumers and the economy. We recommend that regulators and legislators, at both the federal and state levels, examine the resource adequacy problem in restructured markets closely and develop solutions soon. Because of the significant time that is required to develop new resources, we cannot afford to wait until resource adequacy problems pose a threat to the nation’s economy. x ENSURING ADEQUATE POWER SUPPLIES FOR TOMORROW’S ELECTRICITY NEEDS 1. THE RESOURCE ADEQUACY CHALLENGE The Electric Markets Research Foundation (Foundation) critically examines key issues facing the country’s electricity sector arising from industry restructuring that has taken place over the past two decades. The Foundation commissioned Christensen Associates Energy Consulting to examine the ability of the U.S. electric power industry to build and maintain sufficient electric generating capacity to meet the country’s present and future needs. While many regions of the country have undertaken restructuring of both retail and wholesale electricity markets, others have not, so that the U.S. electricity sector now serves consumers under two distinct market models. These models have different impacts upon the development of power facilities and the production and delivery of power. One market model relies on competitive bidding to establish market prices for wholesale power delivered to end-use customers by retail suppliers who may or may not own generation, transmission, and distribution facilities. Restructured market regions utilize regional transmission organizations (RTOs) or independent system operators (ISOs) to operate the competitive wholesale markets. The other market model relies on traditional regulation of vertically integrated utilities that provide generation, transmission and distribution services to end-use customers at prices approved by state regulatory commissions. Within the restructured market regions, many but not all states have adopted retail competition, in which multiple retail suppliers of electric energy and related services compete to serve end-users. The first report published by the Foundation, entitled Evolution of the Electric Industry Structure in the U.S. and Resulting Issues, discusses in significant detail the historical transition to today’s dual market system and the industry’s current status.9 Potentially serious resource adequacy problems were laid bare by the recent “polar vortex” of January and February 2014, when record cold temperatures across most of the eastern and Midwestern United States had the industry scrambling to keep up with the demand for electricity. While the industry managed to avoid blackouts, a general consensus has emerged that the industry came perilously close to exceeding its limits to maintain electric system reliability. While the industry managed to maintain reliability, doing so meant that many electricity consumers in some parts of the country paid unprecedented high prices for electricity during this period. The nation’s ability to cope with a future “polar vortex” will be compromised by the slated retirements over the next few years of many of the generating plants called upon to keep the lights during this last “polar vortex.” Thus the issue of resource adequacy to meet tomorrow’s electricity needs is a critical and timely topic. 9 Navigant Consulting, Inc. op cit. 1 2. SECURITY, ADEQUACY, AND RELIABILITY The physics of electric power systems requires that supply and demand be kept in exact balance at all times and that voltages throughout the systems remain within tight limits. Failure to maintain this balance and proper voltages causes deterioration in power quality and can cause blackouts. Reliability problems occur when system operators lack the resources, information, or judgment to maintain the power balance and voltages. Power system reliability at the transmission level has two major dimensions: security and adequacy. Security depends upon power system operations, particularly including real-time localized deliverability, resource commitment, and dispatch. Adequacy depends upon resource planning and investment, particularly in generation, transmission, and demand-side resources. These two dimensions of reliability are related because security can be maintained only if adequate resources are available to system operators. Security is a short-term concept that refers to the system’s ability to withstand real-time contingencies, particularly outages of major power system facilities (like generators and transmission lines), that would cause demand to exceed supply in some portion(s) of the power system. Without prompt restoration of the power balance either through an increase in supply or controlled but involuntary shedding of firm load, the power system can experience frequency instability, voltage drop, cascading blackouts, and system collapse. Security can change instantaneously due to changes in any of the many factors affecting the power system, including resource availability. Maintenance of security requires that system operators have sufficient resources to be able to respond rapidly to contingencies. A secure power system is one that remains intact and continues to deliver power following some limited amount of equipment failures. Adequacy is a long-term concept that refers to having planned supply- and demand-side resources that exceed forecasted peak loads plus a planning reserve margin to account for forced outages of some generation units. Adequacy thus refers to the relationship between planned resources on the one hand and expected electricity loads and planning reserve requirements on the other hand. Security and adequacy depend upon operating reserves and planning reserves, respectively. Operating reserves are, in any hour or dispatch interval, the amount by which available resources exceed load, where availability is determined not only by resources’ nameplate capacities but also by the speed and extent to which they can respond to contingencies. Planning reserves are, in any year, the amount by which resources’ total nameplate capacity exceeds annual peak loads. Operating reserves and planning reserves are thus indicators of system reliability in short- and long-term timeframes, respectively. The purpose of this report is to examine issues of resource adequacy in both restructured and traditionally regulated markets in the United States. To achieve this purpose, we begin, in Section 3, by providing basic background on electricity market structures and capacity cost recovery mechanisms. Section 4 is devoted to reviewing and assessing the methods by which various industry organizations, government organizations, and regions determine capacity needs. Section 5 presents regional statistics on resource adequacy, resource mix, resource 2 profitability, and capacity prices, and discusses the factors that influence these outcomes. Section 6 describes how technological advances may influence future reliability outcomes. Section 7 discusses various proposals for future reform of the means of assuring adequate capacity. Section 8 provides conclusions. 3. MARKET STRUCTURES Traditionally regulated U.S. electricity markets have a hundred-year history of providing adequate generation capacity under nearly all circumstances. Nonetheless, questions have often been raised about the costs of providing and operating this capacity, particularly about whether the quantity of capacity has been too costly relative to the value of the reliability provided, whether generation investments have been efficient, and whether generation has been operated at least-cost. With such questions in the background, the energy crisis of the 1970s, the nuclear power cost overruns of the 1970s and 1980s, and the contemporaneous movement to deregulate other key infrastructure industries led to a search for new institutional arrangements that would shift generation investment risks from consumers to investors. The basic hope was that such a shift in risk would induce innovation in generation technologies, which did, in fact, occur; but these institutional arrangements also led to new issues and problems, many of which have yet to be resolved. This section begins with an overview of electricity market structures and then describes the two general types of capacity cost recovery mechanisms. 3.1. Overview of Electricity Market Structures About a third of the U.S. population continues to obtain electric power service through wholesale markets that are based on traditional institutional arrangements, while about twothirds of the U.S. population obtains electricity through wholesale markets that have been substantially restructured to allow greater competition at the wholesale and/or retail levels. Both types of market – traditional and restructured – require mechanisms for assuring resource adequacy. This section describes and compares each of these types of markets, and provides an overview of the states in which each market type prevails. 3 3.1.1. Traditional Markets10 In general, utilities with monopoly franchise service territories prevail in those areas of the U.S. that are not served by Regional Transmission Organizations (RTOs), though many such utilities do operate in RTO areas. These utilities are usually required to serve all retail customers within their respective service territories, in exchange for which they are granted an opportunity to earn a return on their investments commensurate with risk. This has commonly been referred to as the “regulatory compact,” which involves an obligation to serve in exchange for exclusive service rights.11 Because of this obligation to serve, utilities must procure sufficient short- and long-term resources to reliably meet customer needs within their service territories. They build and own their own generating units or do so jointly with other utilities, develop long-term purchase arrangements with independent power producers, or procure short- and long-term resources under negotiated bilateral power purchase agreements with entities that have surplus resources. Utilities recover the costs of procuring these resources by charging rates that are determined by their costs of service. A bilateral capacity contract is an agreement between a willing buyer and a willing seller to exchange electricity, rights to generating capacity, or a related product under mutually agreeable terms for a specified period of time. Many non-RTO areas thus have non-centralized bilateral capacity markets in which various capacity suppliers compete to meet resource needs, often by building generation. Even in those areas in which there is little or no retail electricity competition, there may be significant wholesale competition to meet the needs of the monopoly utility. This wholesale competition has been promoted by various regulatory changes (like Federal Energy Regulatory Commission Order No. 88812) that have created nondiscriminatory open transmission access. Resource development continues to be supported by various sharing arrangements among utilities. Some utilities jointly develop and own power plants. Some utilities participate in reserve-sharing arrangements that allow participants to rely upon each other’s capacity, which can reduce overall reserve requirements because of the diversity of different utilities’ loads and resources.13 10 Traditional markets have evolved substantially over the past thirty years, particularly due to changes in law and regulation that have required most utilities, in both traditional and restructured regions, to offer nondiscriminatory open access transmission service and to purchase capacity from third parties under certain conditions. The discussion of traditional markets should not be misinterpreted to suggest that these markets have been fixed in their design or operation, but that they have instead seen less radical change than has characterized restructured markets. 11 There are some cases where limited retail competition is allowed even in states with exclusive franchises. For example, Georgia allows competition for new customers over a certain size. 12 Federal Energy Regulatory Commission, Order No. 888, Promoting Wholesale Competition Through Open Nondiscriminatory Services by Public Utilities, 75 FERC ¶ 61,080, Docket No. RM95-8-000, April 24, 1996. 13 “Diversity” refers to the fact that different utilities serve customers with different load patterns, and different resources are available at different times. For example, California often sends power to the Pacific Northwest in 4 Most states in non-RTO areas have integrated resource planning (IRP) processes that determine resource requirements and that identify the resources that can meet those requirements at the lowest cost to customers. IRP processes consider present and future loads, existing and prospective supply- and demand-side resources, existing and prospective transmission capabilities, risk factors (like fuel diversity), and public policy requirements (like environmental restrictions and renewable resource laws). Based upon all these factors, IRP processes result in utilities building or purchasing capacity sufficient to meet the identified resource needs. Some states require utilities to allow third parties (such as independent generators) to compete, on a non-discriminatory basis, to meet these resource needs. Just as in restructured markets, utilities in traditional markets utilize the principles of cost-based economic dispatch of their capacity resources to minimize overall variable energy costs for customers based on the shortterm incremental costs of each resource. 3.1.2. Restructured Markets The restructured wholesale electricity markets are all located in regions covered by RTOs. The new institutional arrangements of these markets have fostered competition in generation services through new rules for transmission access and pricing and through the creation of RTOs (also called “Independent System Operators”) that direct resource commitment and dispatch over wide geographic areas. Many states in restructured market regions allow retail access. Retail access allows many consumers to shop for their power supply among competing firms, some of which are brokers or marketers that do not own generation. This competition provides incentives for innovation and cost-cutting in the provision of retail electricity services, and it also encourages suppliers to link retail prices to wholesale prices. Although the investments, expenditures, and rates of competitive retail electricity suppliers are not subject to state regulation, these suppliers are subject to light regulatory oversight under consumer protection rules. As a backstop, incumbent electric utilities usually retain an obligation to serve those customers who do not choose alternative suppliers. In the absence of retail access, utilities procure capacity resources in much the same fashion as in traditionally regulated regions, except that capacity trades through the RTOs’ centralized capacity markets are available on a mandatory or voluntary basis depending upon each RTO’s rules. In states with retail access, regulators have often discouraged – or even prohibited – retail load-serving entities (LSEs) from owning their own generating resources, sometimes even barring LSEs from engaging in long-term contracts to hedge against short-term price fluctuations, under the assumption that such contracts would “lock in” high prices and prevent the benefits of competition from accruing to consumers.14 These markets are dominated by the winter, when the Pacific Northwest has its highest electricity demand; and the Pacific Northwest often sends power to California in the summer, when California has its highest electricity demand. 14 For example, under California’s restructuring process retail providers were required or strongly encouraged to purchase all electricity in the spot market, under the assumption that any long-term contracts would become 5 organized spot market transactions in which all generators that clear the market get paid the market price, regardless of actual costs of their generation. These spot market transactions are centrally administered by the RTO, through which electricity can be purchased hourly on a realtime or day-ahead basis. Retail customers may not see this hourly or day-ahead price, however, as their particular contracts or regulatory situation determine the retail rates they pay. The original theory was that, in these restructured wholesale markets, generation investment would be supported by competitively determined market prices for electrical energy and ancillary services which, through locational differentiation, would also induce generators to locate where generation services were most valuable. The reality, however, has been that:  neither producers, consumers, regulators, nor legislators are able or willing to tolerate the extreme and unpredictable price volatility of unfettered electricity markets;  in times of capacity shortage, the political process will not support interruption of service to consumers and retail suppliers who fail to arrange for adequate supplies, but instead tends to “share the pain” of shortages among all consumers, including those who do arrange for adequate supplies;  the RTOs’ short-term markets for electrical energy and ancillary services have not been accompanied by sufficient development of long-term markets for these services; and  the market rules of the RTOs and of regulators occasionally change, usually with significant notice but sometimes unexpectedly. The consequences of these realities have been supplier bankruptcies, disincentives for arranging long-term supplies, the inability of market participants to arrange long-term price hedges, and uncertainty about the durability of market rules. Thus, contrary to the hopes of the 1980s and 1990s, public policy does not allow unfettered electricity markets to support investment in generation and other resources. Instead, the restructured markets have had price caps imposed to limit price volatility, with the result being that, under shortage conditions, the price mechanism does not encourage the provision of sufficient additional resources nor induce sufficient load reductions. Whether simply allowing prices to reflect shortage conditions by eliminating price caps would solve capacity adequacy issues is a moot question since regulators are not likely to allow the price volatility that could result. To avoid the shortages that the price mechanism is not allowed to handle, an assortment of administrative rules have been put in place specifying the quantities and locations of the resources that must be procured. In short, RTO regions’ capacity needs are determined by administrative rules, RTO capacity markets identify the amounts (but not types) of resources uneconomic as competitive pressures caused wholesale prices to fall. This turned out to be an extremely costly mistake when wholesale prices skyrocketed in the winter of 2000-01 and 100% of the non-municipal load in the state was unhedged. 6 that meet these needs, and it is hoped that the resulting capacity prices will support investment. This approach has not been enough to fully solve the resource adequacy problem, however, because the RTOs’ capacity markets cover at most only the first few years of the life of decades-long generation investments, and because there are uncertain relationships between capacity on the one hand and the energy and ancillary services that they provide on the other. RTOs’ determinations of capacity needs must therefore evolve over time to reflect how renewable resource intermittency, changing forced outage rates of power system components, uncertain future technological change, uncertain future economic conditions, uncertain electricity market rules, and uncertain future government regulatory policies affect the uncertain ability of capacity to provide the energy and ancillary services that consumers need.15 3.1.3. Overview of Prevalent Market Types in Each State In addition to the distinction between traditional and restructured electricity markets, there is also a distinction among the states in their authorization of retail access. This latter distinction is important because it has influenced how the states deal with resource adequacy. For example, states without full retail access (such as Georgia16 and North Carolina) rely on integrated resource planning. Unlike full retail access states, they have not ordered their utilities to acquire capacity through a reverse auction of load responsibility (as occurs in New Jersey) or with regular utility semi-annual wholesale power procurements (as occurs in Maryland). The RTO regions also encompass retail markets that have not restructured. In these situations, wholesale market prices are largely determined by the centralized RTO markets, while retail prices are determined on a traditional cost-of-service basis, where costs are influenced by prices in the RTOs’ wholesale markets. Considering these two dimensions – traditional versus restructured markets, retail access versus no retail access – we divide the 48 contiguous states and the District of Columbia into the three groups:  Restructured Retail Access States that are within RTOs and that permit retail competition among suppliers; 15 The current Federal Energy Regulatory Commission proceeding on revisions to the capacity market of the Midcontinent Independent System Operator (Docket No. ER11-4081-001) is the latest in a series of FERC proceedings to revise key characteristics of the capacity markets under its jurisdiction. Texas, meanwhile, is in the midst of a long and contentious process by which it seems to be heading toward adopting its own RTOadministered capacity market. 16 Some retail competition has been present in Georgia since 1973 with the passage of the Georgia Territorial Electric Service Act. This Act enables customers with manufacturing or commercial loads of 900 kW or greater a one-time choice in their electric supplier. It also provides eligible customers the opportunity to transfer from one electric supplier to another if all parties agree. See http://www.psc.state.ga.us/electric/electric.asp. 7  Restructured Non-Retail Access States that are within RTOs and that do not permit retail competition; and  Traditionally Regulated States that are not within RTOs and that do not permit full retail competition. As shown in Figure 1, all states with retail access are all located in regions covered by RTOs, so no state falls in the theoretically possible category of being a non-RTO state with full retail access. Instead, 13 states and the District of Columbia, mainly concentrated in the Northeast, are covered by RTOs and offer retail access; 11 states, mainly concentrated in the Midwest, are covered by RTOs and permit little or no retail competition; and 24 states, mainly concentrated in the Southeast and West, do not have RTOs and permit little or no retail competition. Figure 1 Division of States by Retail Access Status17 3.1.4. Similarities and Differences Among the Market Types Table 1 shows how the three market types – restructured retail access, restructured non-retail access, and traditionally regulated – are similar to and different from one another. In all 17 Compete Coalition, http://www.competecoalition.com/about. 8 markets other than Texas,18 LSEs have an obligation to procure capacity – either owned or procured under contract – that is sufficient to serve their own retail load. The RTOs offer an additional venue – their centralized capacity markets – in which LSEs can procure capacity. Consumers have a choice of retail supplier only in markets with retail access, in exchange for which utilities have a more limited obligation to serve than in markets without retail access. 19 While retail rates continue to be cost-based in markets without retail access, they are more market-based in markets with retail access in that the energy portion of rates depends on a pass-through of the wholesale cost of the electricity procured in the wholesale market. Table 1 Similarities and Differences Among Market Types Characteristic Capacity planning forum LSE obligation to procure capacity sufficient to serve own load Acceptability in meeting capacity obligation: Owned capacity Bilaterally contracted capacity Centralized market purchases Consumer choice of supplier Utility obligation to serve Market Type Restructured NonRetail Access Traditionally Regulated RTO / IRPs IRPs no yes yes yes yes yes yes yes yes yes yes not applicable No, or severely restricted yes No, or severely restricted yes Restructured Retail Access RTO / IRPs or LTRPs20 mostly yes limited 18 In Texas, retail energy providers (REPs) serve retail electric consumers without bearing a requirement to secure capacity sufficient to meet their load. 19 In retail access states, distribution utilities have an obligation to serve customers regardless of which supplier the customer chooses. The investments, expenditures, and rates of distribution utilities are still regulated by state regulatory agencies. In addition, distribution utilities are required in most retail access states to offer “default service” to customers who, for whatever reason, do not actually choose a supplier or cannot obtain service from a competitive supplier. The prices and terms of this default service are also regulated by the state regulatory agency. 20 Requirements for long-term resource plans (LTRPs) differ from requirements for IRPs. For LTRPs, planning periods are typically ten years, although some states require a five-year planning period with yearly updates. Because utilities in states with LTRPs operate in restructured retail markets and typically do not own generation, LTRPs evaluate purchases for capacity and energy, as well as energy efficiency and other demand-side management programs. 9 Basis of retail rates market prices for energy and reserves, cost for wires cost cost Figure 2 shows that a vast majority of the states have an IRP requirement, including a significant number of states that are part of an RTO. Furthermore, many other states in RTO regions require LSEs to file long-term resource plans that supersede the IRPs that existed prior to the restructuring of the retail market. Figure 2 States with Integrated Resource Planning or Similar Processes21 3.2. Capacity Cost Recovery Mechanisms In principle, there are two basic methods by which the required amount of capacity can be determined. First, the required amount of capacity can be determined through purely market 21 Synapse Energy Economics Inc., Best Practices in Electric Utility Integrated Resource, June 2013, Figure 2, p. 5. 10 processes, whereby investors build capacity when they expect that the market prices of electricity services will be sufficiently high to make their investments profitable.22 Second, some agency – like a reliability organization, state regulators, RTOs, or utilities themselves – can determine the capacity requirement. The methods by which capacity costs are recovered are determined, in large part, by the methods for determining the capacity requirement. When the capacity requirement is determined by the market, capacity costs must be recovered through market prices. When the capacity requirement is determined by an agency or by a utility satisfying a regulatory requirement, there needs to be some scheme for more or less guaranteeing recovery of prudently incurred costs. 3.2.1. Cost Recovery Under a Purely Market Scheme Under a purely market scheme, there would be no “capacity” product. Instead, investors would develop resources when they expect to profit from the sales of energy and ancillary services at projected market prices. Such sales may be at spot (real-time) prices, but resource owners and customers would generally seek to avoid price volatility through derivative contracts such as long-term bilateral sales contracts and option contracts. Capital costs and operating costs would be recovered solely through revenues from the sale of these services. When demand threatens to exceed available capacity, high energy and ancillary services prices would encourage immediate load reductions, often through demand response programs (though in some instances through utility-imposed load curtailments); and investment would respond to expectations of persistent high prices. That is the theory. In real electricity markets, by contrast, energy and ancillary services prices are significantly distorted, and cost recovery is seriously undermined, by the following circumstances and policies:  In some RTO regions, limited demand-side participation and electricity customers’ general insulation from volatile wholesale electricity prices restrict the extent to which market prices and capacity choices are influenced by consumers’ values of electricity services.  RTOs’ out-of-market purchases of energy and ancillary services, by increasing short-term energy and reserve supply for the purpose of improving short-term reliability, have the side-effect of depressing energy and reserve prices.23 22 As discussed below, this first approach is not likely to result in capacity sufficient to meet traditional capacity requirements or the laws or regulations related to such requirements. 23 The RTOs’ system operators often find that the market cannot be relied upon to provide sufficient energy and ancillary services in the right locations. Consequently, for the purpose of assuring power system reliability, they make “out-of-market” side deals by which they pay particular generators to provide energy, voltage support, or operating reserves that these generators would not be willing to provide at market prices. The RTOs recover these 11  Energy and ancillary service prices are generally subject to caps, partly to reduce the price volatility borne by consumers and partly because of concerns that high prices may be due to exercises of supplier market power. These price caps limit cost recovery under shortage conditions, thereby depriving capacity resources of what could otherwise be a significant source of revenues. This leads to the so-called “missing money” problem, which inhibits new investment in restructured markets.  The investment problem is particularly acute because of the nature of electricity demand. Customer demand has a profile that includes baseline needs during normal weather conditions and usage, and higher peak demands during particularly cold or hot weather (depending on the region). A mix of generating technologies satisfies this range in electricity demand at least cost. The generators that serve demand only during peak load hours may be needed to run only a few days or even a few hours each year. Although such peaker plants have relatively low capital costs, they nonetheless need extremely high prices during those few days or hours to earn revenues sufficient to cover both the variable and fixed costs, including a return on their investment in capacity. Inconsistent with this need, however, the restructured markets have caps on generators’ offer prices, thus precluding market prices from reaching levels high enough to provide the needed revenue for the peaker plants during those few hours when they are needed. This “missing money” problem extends beyond peaker plants to all other plant types, including baseload plants. The restructured markets’ capacity market mechanisms are intended to make up for the “missing money” and provide sufficient incentives for investment in both base load and peaking generation – so far with limited success.  Policies that support particular types of capacity resources – such as renewable resource portfolio standards or tax credits for renewable resource investments – have the implicit effect of subsidizing the preferred resources while “taxing” other resources. The “tax” on other resources occurs in the form of reduced market prices for energy, ancillary services, and capacity due to the presence and operation of the preferred, subsidized resources. 24,25 extra payments through uplift charges of various sorts, generally imposed on all load. The generators who receive these payments supply of energy and ancillary services that they would not provide without these payments; and this extra supply has the effect of reducing energy and ancillary services prices relative to what they would otherwise be. 24 This is the gist of the Electric Power Supply Association’s complaint that capacity and energy markets are undermined by price discrimination in favor of certain preferred resources. See Statement of Michael M. Schnitzer, Co-founder and Director of The NorthBridge Group, on behalf of the Electric Power Supply Association, Centralized Capacity Markets in Regional Transmission Organizations and Independent System Operators, before the Federal Energy Regulatory Commission, Docket No. AD13-7-000, September 9, 2013. 25 The size of this tax on other resources has been estimated for the Texas power market for the years 2013 through 2015. For this period, Texas’ state renewable resource policies will depress peaker margins by about $6 per kW-year and natural gas combined-cycle margins by about $14 per kW-year. See M. Kline, B. Gibbs, and R. 12  U.S. power industry practice sets planning reserve requirements at levels that exceed many customers’ willingness to pay for reliability.26 In general, it might be cheaper for many customers to suffer more bulk power system-related outages than to pay for the resources needed to avoid those outages, even considering (for example) business customers’ costs of lost production, lost sales, and additional production equipment repair and maintenance costs following an unexpected outage. Outage costs do vary widely among customers. Nonetheless, because many customers’ willingness to pay for reliability is generally well below that needed to support the power industry’s usual planning reserve requirements as determined by public policy, markets alone will not support the capacity requirements implied by the power industry’s reliability practices, even with a perfectly functioning demand-side of electricity markets. The latter four policies all restrict or reduce market prices; and the latter two policies require capacity that would not be supported by free markets. Eliminating these policies is simply not realistic. Consequently, given the likelihood that these policies and market design practices will remain in place, capacity costs will not be recoverable under a purely market scheme and investment in new capacity will continue to be suppressed. 3.2.2. Cost Recovery With a Capacity Requirement Scheme Capacity requirement schemes characterize both traditional and RTO markets. Such schemes impose capacity obligations on individual LSEs for specified present and future periods (such as three years ahead). These obligations can be enforced through penalties, or LSEs may meet their requirements merely as a matter of good business practice. Capacity requirements are generally set at some level in excess of the LSE’s customers’ peak loads plus any wholesale sales obligations that the LSE may have under contract. This excess is Muthiyan, “When Free Markets Aren’t Free: Failure of the ERCOT Energy-Only Market,” Berkeley Research Group, August 2013, p. 1. 26 For example, one report finds that ERCOT’s reliability target of “one load-shed event in 10 years” implies a need for a 15.25% reserve margin; but customer willingness-to-pay $9,000 per MWh to avoid curtailment implies a need for only a 10% reserve margin. See S. Newell, K. Spees, J. Pfeifenberger, R. Mudge, M. DeLucia, and R. Carlton, ERCOT Investment Incentives and Resource Adequacy, Brattle Group, prepared for Electric Reliability Council of Texas, June 1, 2012, p. 3. The $9,000 value is roughly the magnitude of multiple studies of the costs that customers incur due to curtailment. Another report finds that the reliability target of “one load-shed event in 10 years” implies customer willingnessto-pay of $300,000 per MWh to avoid curtailment, an absurd result that is equivalent to an average homeowner paying $900 for one hour’s worth of power. The $300,000 figure assumes that: a) the carrying cost of new capacity is $90,000 per MW-year; and b) that a typical resource-related firm load shed event lasts three hours. $300,000 = $90,000 per MW-year / [(3 hours per event) / (1 event per 10 years)]. Note that the $90,000 figure is consistent with the $891 per kW cost of a combustion turbine peaking unit shown in Figure 16: $90,000 = $891 per kW * 1000 kW per MW * 10.1% cost of capital. See Astrape Consulting, The Economic Ramifications of Resource Adequacy, for Eastern Interconnection States’ Planning Council and National Association of Regulatory Utility Commissioners, January 2013, p. 1. 13 the planning reserve margin, usually a number in the range of 12% to 18% of peak load. The determination of capacity requirements thus depends upon load forecasts, which are more uncertain for individual LSEs in competitive retail situations wherein customers may shift among LSEs than in monopoly situations in which a single LSE can count on serving the whole market. LSEs can fulfill their capacity obligations through resource ownership or resource rights conferred by contract. Contractual resource rights may be procured in bilateral markets and, in some RTOs, in centralized capacity markets.27 There is some complexity, however, in defining precisely what qualifies as “capacity” that meets the obligations. In principle, elements of this definition could include the following:  supply-side versus demand-side resources versus transmission resources;  resource technology (such as fuel type);  performance requirements (such as minimum availability rates, speed of availability, dispatchability by the system operator);  requirements for substantiating expected performance;  requirements for power deliverability;  requirements for firm fuel transportation;  timeframe of the capacity obligation (such as one month ahead or five years ahead); and  quantification of capacity (such as crediting dispatchable resources with their full nameplate capacities while crediting intermittent resources with only a quarter of their nameplate capacities). Capacity investors must have a reasonable expectation that they will recover the capital costs of their investments regardless of the institutional arrangements under which the investment is made. The capital cost recovery methods are very different under traditional regulatory schemes than under restructured market schemes. Traditional Recovery Through Cost-of-Service Based Rates Traditionally, capacity costs have been recovered from retail customers through retail charges based upon those costs. In general, cost-of-service ratemaking annualizes capacity costs according to some measures of capital costs (like interest rates), assigns these costs to the utility’s functions (particularly generation), allocates the functionalized costs among customer classes or groups, and then divides class-level costs by some class-level billing determinants (like peak loads or energy sales) to derive retail prices. The costs that are recovered through 27 LSE participation in centralized capacity markets may be mandatory or voluntary, depending upon the RTO. 14 these retail prices may be lower or higher than costs actually incurred depending upon the accuracy of the forecasts (particularly the load forecasts) that went into the price calculation. There are two main factors that make traditional recovery of capacity costs uncertain. The less important factor is the inevitable misforecasting of the loads and costs that underlie the calculation of retail prices. These misforecasts might reasonably be expected to offset each other over the life of a capacity resource, which makes the uncertainty relatively minor over the resource’s life. The more important factor, for regulated utilities, is uncertainly of the extent to which regulators will accept the prudency of capacity investments, which depends, in large part, on the extent of any capacity cost overruns. In short, under traditional regulation, the prudency of a capacity resource investment largely determines the uncertainty in the recovery of capacity costs. A utility can pretty much count on recovering those capacity investment costs deemed prudent by regulators. Competitive Recovery With Capped Energy and Ancillary Services Prices Recovery of capacity costs in a competitive market context requires either: a) regulatory or administrative support of market prices, such as Minimum Offer Price Rules that discourage investment in some capacity resources as a counterbalance to those policies that encourage investment in other (possibly subsidized) capacity resources; and/or b) imposition of implicit “taxes” on electricity consumers, which is accomplished primarily through the capacity requirements imposed on LSEs. It also requires the imposition upon LSEs of stiff penalties for failure to procure sufficient capacity – through owned or purchased capacity – to meet their respective requirements. Because of the policies (enumerated in Section 3.2.1) that distort and depress the market prices of electricity services, capacity cost recovery in competitive markets depends upon the mandatory resource requirements imposed upon LSEs. Because the mandatory requirements raise the costs of all LSEs, each individual LSE is able to raise its retail prices to recover these costs without fear of losing customers to competitors. Nonetheless, these mandatory requirements have, in practice, often been insufficient to assure full capacity cost recovery and thereby provide insufficient incentives for investors to develop new resources. 4. DETERMINATION OF CAPACITY REQUIREMENTS Capacity requirements are determined first and foremost by the need to maintain power system reliability. Reliability needs are generally translated into capacity requirements through various rules of thumb that are implemented through engineering analysis of probable reliability outcomes, with the objective of minimizing costs subject to meeting the reliability requirement. This section describes the regulatory context in which capacity requirements are determined, and then looks at the actual and proposed practices of certain entities responsible for assessing resource adequacy. 15 4.1. Regulatory Context Various reliability and regulatory agencies impose overlapping rules on the utilities, transmission owners, and system operators who are responsible for the day-to-day and minuteto-minute tasks of maintaining power system reliability. In general, the national standards set minimum criteria, while more local standards can set higher criteria. For example, resource adequacy in New York State depends upon the various rules established by the North American Electric Reliability Corporation (NERC), the Northeast Power Coordinating Council (NPCC), the New York State Reliability Council (NYSRC), the Federal Energy Regulatory Commission (FERC), the New York Public Service Commission, and the New York Independent System Operator (New York ISO).28 Because of the particular reliability needs of the northeast region, NPCC regional level standards may be more stringent than the nationallevel standards of NERC. Because of New York’s particular reliability needs, NYSRC’s state-level standards may be more stringent than the regional-level standards of NPCC. Following the national-to-local scheme, this section begins at the highest level – the North American Electric Reliability Corporation – and then sequentially looks at Regional Reliability Entities, FERC, and state requirements. 4.1.1. North American Electric Reliability Corporation Standards29 NERC develops reliability standards in collaboration with stakeholders in the U.S. and Canadian bulk power systems. The standards are based upon power engineering models that estimate how actual and proposed standards are likely to affect the bulk power system’s performance and risks.30 NERC does not set reserve margins or mandate resource development (such as the building of generation or transmission facilities). Instead, NERC develops reliability standards, independently assesses reliability issues, and identifies emerging reliability risks. NERC’s Reliability Standards define the power system operating and planning requirements to which each entity responsible for operating or planning the bulk power system must adhere. Each standard must be consistent with all of the following Reliability Principles:31 28 New York State Reliability Council, Reliability Rules For Planning And Operating the New York State Power System, Version 31, May 11, 2012, p. 4. 29 Sources of this section include http://www.nerc.com/pa/stand/Pages/default.aspx; North American Electric Reliability Corporation, Reliability Standards for the Bulk Electric Systems of North America, December 12, 2013, http://www.nerc.com/pa/Stand/Reliability%20Standards%20Complete%20Set/RSCompleteSet.pdf; and North American Electric Reliability Corporation, Reliability and Market Interface Principles, undated, http://www.nerc.com/pa/Stand/Standards/ReliabilityandMarketInterfacePrinciples.pdf. 30 http://www.nerc.com/pa/stand/Pages/default.aspx. 31 North American Electric Reliability Corporation, “Reliability and Market Interface Principles,” undated, http://www.nerc.com/pa/Stand/Standards/ReliabilityandMarketInterfacePrinciples.pdf. 16 Reliability Principle 1 Interconnected bulk electric systems shall be planned and operated in a coordinated manner to perform reliably under normal and abnormal conditions as defined in the NERC Standards. Reliability Principle 2 The frequency and voltage of interconnected bulk electric systems shall be controlled within defined limits through the balancing of real and reactive power supply and demand. Reliability Principle 3 Information necessary for the planning and operation of interconnected bulk electric systems shall be made available to those entities responsible for planning and operating the systems reliably. Reliability Principle 4 Plans for emergency operation and system restoration of interconnected bulk electric systems shall be developed, coordinated, maintained and implemented. Reliability Principle 5 Facilities for communication, monitoring, and control shall be provided, used, and maintained for the reliability of interconnected bulk electric systems. Reliability Principle 6 Personnel responsible for planning and operating interconnected bulk electric systems shall be trained, qualified, and have the responsibility and authority to implement actions. Reliability Principle 7 The security of the interconnected bulk electric systems shall be assessed, monitored, and maintained on a wide-area basis. Each standard must also be consistent with all of several Market Interface Principles that are intended to facilitate electricity competition without discriminating in favor of or against any particular market participant. 4.1.2. Regional Reliability Entities Standards NERC delegates authority to regional reliability entities that are responsible for promoting and improving the reliability, adequacy, and critical infrastructure of their respective regional power systems. These entities serve each of the several NERC reliability regions shown in Figure 3. Each regional entity develops, updates, monitors, and enforces reliability standards within its own region, without discrimination among market participants. These standards may be tailored to regional circumstances, but must be consistent with NERC standards. The regional reliability entities may also help coordinate power system planning, design, and operations. For each of the eight regional reliability entities, resource requirements – or, equivalently, planning reserve requirements – are determined as follows: 17  Florida Reliability Coordinating Council (FRCC), in collaboration with the Florida Public Service Commission, requires that investor-owned utilities (IOUs) maintain a 20% planning reserve margin while non-IOUs maintain a 15% reserve margin.32  Midwest Reliability Organization (MRO) has two subregions – Mid America Power Pool (MAPP) and the Midcontinent Independent Transmission System Operator (MISO). MAPP uses NERC’s 15% reserve margin target for utilities within that sub-region of the MRO. Resource requirements in MISO are determined as described in Section 4.2.1.  Northeast Power Coordinating Council (NPCC), in its U.S. portion, is divided between ISO New England and the New York ISO. The reliability criteria and targets for planning reserve requirements for these RTOs are determined as described in Section 4.2.1. Figure 3 NERC Reliability Regions33 32 North American Electric Reliability Corporation, 2013 Summer Reliability Assessment, May 2013, p. 8. 33 The reliability regions are Florida Reliability Coordinating Council (FRCC), Midwest Reliability Organization (MRO), Northeast Power Coordinating Council (NPCC), ReliabilityFirst Corporation (RFC), SERC Reliability Corporation (SERC), Southwest Power Pool Regional Entity (SPP), Texas Reliability Entity (TRE), and Western Electricity Coordinating Council (WECC). 18  ReliabilityFirst Corporation (RFC) is split between Midcontinent ISO and PJM. Therefore, the reliability criteria and targets for these RTOs’ planning reserve requirements are established as described in Section 4.2.1.  SERC Reliability Corporation (SERC) is guided by the NERC benchmark of 15% planning reserves as well as by reliability criteria that apply to each of the sub-regions and power systems within SERC. SERC uses region-wide reliability criteria only to the extent that the criteria applied to smaller areas do not adequately address reliability for the whole region. Subject to the foregoing and to the condition that each financial entity within SERC is responsible for serving its own load, each financial entity determines its own planning reserve requirement. Nonetheless, capacity planning is coordinated among the entities within each sub-region.  Southwest Power Pool Regional Entity (SPP) has a Reference Margin Level of 13.6%.34  Texas Reliability Entity (TRE) has a Reference Margin Level of 13.75%. This figure is based on a target of no more than 0.1 loss-of-load events per year.35 Electric Reliability Council of Texas (ERCOT) stakeholders are currently reviewing a recently completed loss-of-load study that supports the target reserve margin determination. A final decision by the ERCOT Board is expected later this summer.  Western Electricity Coordinating Council (WECC) covers a very large geographic region that is divided into 19 reliability assessment zones. Target reserve margins in the U.S. zones for summer range between 12.6% and 17.9%, averaging 14.8%, while those for winter range between 11.0% and 19.9%, averaging 14.3%. For the Canadian zone, the figures are 12.4% and 14.0%, while for the Mexico zone, the figures are 11.9% and 10.7%. Thus, the U.S. zones tend to have higher target reserve margins than those of Canada and Mexico. For WECC as a whole, that target reserve margin is 14.6% in both summer and winter.36 In addition to regional entities, there are sub-regional entities (like the NYSRC) that may impose reliability standards that go beyond those of the regional entities. 4.1.3. Federal Energy Regulatory Commission Requirements FERC has issued several important orders pertaining to the organization of RTO capacity markets. Some of these orders have been generic orders that address market design issues, among which capacity markets and/or resource adequacy issues are a part.37 Other orders 34 North American Electric Reliability Corporation, 2013 Summer Reliability Assessment, May 2013, p. 142. 35 North American Electric Reliability Corporation, 2013 Summer Reliability Assessment, May 2013, p. 19. 36 Western Electricity Coordinating Council, 2012 Power Supply Assessment, October 15, 2012, Table 7, p. 7. 37 These include, for example, Order No. 719 (Federal Energy Regulatory Commission, Wholesale Competition in Regions with Organized Electric Markets, 125 FERC ¶ 61,071, Docket Nos. RM07-19-000 and AD07-7-000, October 19 have addressed the details of how individual RTO’s capacity markets are designed.38 The general thrust of these orders has been to promote the following:  Non-discriminatory treatment of generation, demand response, and transmission as capacity resources;  Recognition of the importance of capacity locations, to account for transmission constraints that limit deliverability;  Encouragement of advance commitment of capacity, to support planning and allow time for capacity construction or development;  Determination of capacity prices according to peaking plant revenue requirements net of energy and ancillary service market revenues. Within the general thrust of its policy, FERC has allowed the RTOs significant latitude in setting the details of how their capacity markets work, including differences in how the RTOs determine capacity requirements, define capacity, set capacity performance requirements, mandate capacity market participation, set the timing of capacity commitments, conduct auctions, determine capacity prices, and mitigate market power. 4.1.4. State Requirements State reliability requirements are consistent with those established by NERC, the Regional Reliability Entities, and FERC. They do, however, sometimes go beyond the national and regional requirements. 4.2. Requirements of the Regional Transmission Operators This section describes, compares, and assesses the methods by which each of the RTOs’ determines its capacity requirements. 4.2.1. Methods for Determining Capacity Requirements Capacity requirements are usually determined by the amount of capacity that will achieve some reliability target (like one outage event in ten years) under peak load conditions. The critical determinants of capacity requirements are therefore the reliability targets, forecast peak loads, and the modeling assumptions that relate power system conditions to reliability outcomes. 17, 2008) and Order No. 745 (Federal Energy Regulatory Commission, Demand Response Compensation in Organized Wholesale Energy Markets, 134 FERC ¶ 61,187, Docket No. RM10-17-000, March 15, 2011). 38 These include, for example, Federal Energy Regulatory Commission, Initial Order on Reliability Pricing Model, PJM Interconnection, L.L.C., 115 FERC ¶ 61,079, Docket Nos. EL05-148-000 and ER05-1410-000, April 20, 2006; and Federal Energy Regulatory Commission, Order Accepting Market Rules, ISO New England, Inc., 119 FERC ¶ 61,239, Docket No. ER07-547-000, June 5, 2007. 20 Because of transmission limitations, capacity requirements are set by zones that are defined by existing transmission constraints. Significant changes in power system configurations, notably including additions or retirements of generation or transmission facilities, can change the definitions of zones. Retail choice creates substantial uncertainty in the quantity of load that will be served by any LSE. For a monopoly utility, the load in any particular year is uncertain because of the major common factors – weather and economic conditions – that affect all loads and are uncertain on an annual time scale. For LSEs competing to serve customers, the load in any particular year depends not only on the major common factors but also on competitors’ business strategies, consumer preferences, market campaign successes and failures, and other competitive conditions. Consequently, the load uncertainty faced by an LSE in a retail choice environment is proportionally much greater than the load uncertainty faced by an LSE in a market without retail choice. Because each LSE’s capacity obligation depends upon the quantity of load that it serves, the obligation in retail choice environments is proportionately much more uncertain than in nonretail choice environments. Furthermore, this relatively larger uncertainty increases with longer forward timeframes. For example, an LSE’s capacity obligation is much more uncertain three years in advance than one month in advance. California Independent System Operator The California Independent System Operator (California ISO) tariff requires LSEs to have generation capacity equal to at least 115% of each month’s forecast peak demand. The 15% planning reserve requirement covers operating reserves (about 7% of load) plus an allowance for resource outages and other potential resource deficiency issues (about 8% of load). LSEs may be required to procure additional resources to address reliability issues in certain local areas. Electric Reliability Council of Texas ERCOT does not have a capacity market, though it is considering the possibility of adopting one.39 Although a 13.75% planning reserve margin is implied by its target reliability standard of one-in-ten-year loss-of-load expectation (LOLE), ERCOT does not have a formal resource adequacy requirement. Instead, LSEs procure resources as they think appropriate in accordance with their expectations of future electrical energy prices. Consequently, actual planning reserves in the ERCOT market are the aggregate result of LSEs’ individual investment decisions. 39 The Public Utility Commission of Texas together with the ERCOT has commissioned a significant amount of research into the question of how best to ensure resource adequacy in Texas. A contentious debate continues over whether the Texas electricity market needs a formal capacity market to solve its resource adequacy issues. A most recent addition to the research on the question is The Brattle Group, Estimating the Economically Optimal Reserve Margin in ERCOT, prepared for the Public Utility Commission of Texas, January 31, 2014. 21 ISO New England ISO New England forecasts loads according to historical loads and forecasts of future real income and real electricity prices.40 Based upon this load forecast, it determines the amount of additional capacity, on top of existing capacity, that would be needed to achieve a one-in-tenyear LOLE. With various adjustments for Hydro-Québec Interconnection Capability Credits and import capability, the Installed Capacity Requirement (ICR) is then set equal to: a) existing capacity; times b) one plus the ratio of the needed additional capacity to summer peak load.41 ISO New England has capacity requirements for each of four Capacity Zones: the Maine Load Zone, the Connecticut Load Zone, the Northeastern Massachusetts Load Zone, and the Rest of Pool Capacity Zone.42 Midcontinent Independent Transmission System Operator Resource adequacy requirements in the MISO region are set by state regulators and influenced by stakeholders and FERC. Resource adequacy requirements therefore vary by state. Nonetheless, MISO performs an annual LOLE study that serves as the basis for its minimum Planning Reserve Margin (PRM) for the upcoming planning year and its PRM forecast for the subsequent nine years. The LOLE study considers generators’ performance, planned maintenance outages, and forced outages; load forecast uncertainty; and transmission congestion. MISO relies on its members for load and other information that determines the PRM. The PRM is not mandatory. New York Independent System Operator New York ISO’s capacity requirement equals forecast peak load plus an Installed Reserve Margin (IRM) requirement.43 New York ISO forecasts peak load by escalating historical peak loads according to forecast growth of loads and of dispatchable load management programs. 44 The NYSRC sets the IRM requirement to achieve a one-in-ten-year LOLE, where the calculation of the LOLE depends upon “demand uncertainty, scheduled outages and deratings, forced outages and deratings, assistance over interconnections with neighboring control areas, NYS 40 ISO New England, Regional Long-Run Energy and Peak Load Forecast (2012-2021), System Planning, presentation to NEPOOL LFC Meeting, January 31, 2012. 41 ISO New England, ISO New England Installed Capacity Requirement, Local Sourcing Requirements, and Maximum Capacity Limit for the 2014/15 Capability Year, April 2011, p. 11 and p. 25. 42 ISO New England, Market Rule 1, Section III.12.4, p. 143. 43 New York Independent System Operator, Installed Capacity Manual, August 2011, p. 2-3. 44 New York Independent System Operator, NYISO Load Forecasting Manual, Manual 6, April 2010, pp. 1-1 – 1-2, http://www.nyiso.com/public/markets_operations/documents/manuals_guides/index.jsp. 22 Transmission System emergency transfer capability, and capacity and/or load relief from available operating procedures.”45 PJM PJM’s capacity requirement equals forecast peak load plus an IRM requirement. PJM considers weather conditions and economic growth in its forecasts of peak loads.46 It sets the IRM requirement so as to achieve an “acceptable level of reliability” as determined by forecasts of loads, generator forced outage rates, and generator maintenance schedules.47 PJM differentiates capacity requirements by Locational Deliverability Area, each of which is defined by actual past transmission constraints, potential future transmission constraints, or a perceived reliability need. Southwest Power Pool Southwest Power Pool (SPP) requires that most LSEs have capacity equal to at least 112% of their system peak responsibility, while LSEs with resources that are at least 75% hydroelectric are required to have capacity equal to at least 109% of their system peak responsibility.48 Each LSE’s “system peak responsibility” is defined as its peak annual load plus firm wholesale power sales at the time of its annual peak less firm wholesale power purchases at the time of its annual peak. 4.2.2. Determination of Capacity Prices In a market context, the incentives for resource investment depend upon the costs that can be recovered through markets over the long term. Because these markets include capacity markets, the determination of capacity prices can affect resource investment incentives. In the eastern RTOs (that is, New England, New York, and PJM), centralized market capacity auctions are held for specific future time periods (up to four years in advance) and at specific intervals. The auctions may have several rounds to allow market participants to adjust their positions and find market equilibrium. Resources that are accepted in each auction are those that have bid below the relevant market-clearing price: they are paid a market-clearing price that reflects the netting of the revenues (if any) that a pure peaking generator would earn from energy and ancillary services sales. Capacity prices are determined by the intersections of supply and demand curves for each season and each relevant capacity market zone. Supply 45 New York State Reliability Council, LLC, New York Control Area Installed Capacity Requirements for the Period May 2012 - April 2013, December 2, 2011, p. 3. 46 PJM Interconnection, Load Forecasting and Analysis, Manual 18, November 16, 2011. 47 PJM Interconnection, PJM Capacity Market, Manual 18, November 11, 2011, p. 7 and p. 9; and PJM Interconnection, PJM Resource Adequacy Analysis, Manual 20, June 1, 2011, pp. 21-34. 48 Southwest Power Pool, Southwest Power Pool Criteria, Section 2.1.9, April 25, 2011. 23 curves are determined by the capacities and offer prices of the resources offered in each auction. Demand curves are administratively determined by each RTO, and depend principally upon the estimated cost of new entry of a pure peaking generator (net of energy and ancillary services revenues) and the capacity that is required to meet reliability criteria for each zone. The market-clearing price and the market-clearing quantity are determined by the intersection of the supply and demand curves. In the event of failure to perform, accepted resources may be penalized and may be liable to pay for replacement capacity. ISO New England has a mandatory centralized capacity market through which LSEs trade capacity up to three years in advance and, for new capacity, can obtain guaranteed prices for up to five years. Its auction begins at a high price that yields more capacity than the ICR. The price is then reduced until the cleared capacity exactly meets the ICR and the requirements for each of local capacity zones. Existing capacity resources are price-takers that clear the auction automatically. New capacity resources, which are those that have not cleared in a previous auction, must bid to receive compensation. Only new capacity offers determine the clearing price, while existing capacity resources influence the clearing price only by exiting the auction. Capacity and capacity prices are differentiated by zone. MISO has a voluntary centralized capacity market through which LSEs can trade capacity one year in advance. LSEs can opt out of the centralized market if they procure sufficient resources through resource ownership or bilateral contracts. LSEs without sufficient resources must pay a penalty charge that is based upon the cost of new entry. New York has a mandatory monthly spot market auction through which LSEs trade capacity up to one month in advance. It also runs voluntary six-month strip and monthly auctions for each summer and winter “capability period”. Capacity suppliers indicate the quantities and prices of their offers; and offers are accepted up to the point that the resulting supply curve meets the demand curve. LSEs are allowed to self-supply part or all of their capacity obligations. Capacity and capacity prices are differentiated by zone. PJM has a mandatory centralized capacity market through which LSEs trade capacity up to three years in advance and in which new capacity can obtain guaranteed prices for up to three years. A Base Residual Auction (BRA) is held for a delivery year three years in the future. To allow market participants to make adjustments in their capacity resources by selling excess capacity or purchasing additional amounts to make up capacity deficiencies, three additional auctions may be held for each delivery year, occurring twenty, ten, and three months, respectively, prior to the delivery year.49 The BRA determines the capacity price based upon a mathematical optimization program that finds the intersection point of capacity supply offers, and an administratively determined, downward sloping “capacity demand curve.” The 49 The three additional capacity auctions allow LSEs to adjust their capacity purchases to changing circumstances. Also, a conditional incremental auction may be held if a need to procure additional capacity results from a delay in a planned large transmission upgrade that was modeled in the BRA for the relevant delivery year. 24 optimization considers deliverability constraints that define capacity pricing zones. In general, LSEs are allowed to self-supply only capacity that clears the centralized market.50,51 Figure 4 shows samples of the capacity demand curves used by the three eastern RTOs. The curves for the New York ISO and PJM begin at high capacity price levels when reserve margins are very low, then fall continuously as reserve margins rise, finally reaching zero prices at high reserve levels. The downward slope of these curves reflects the usual economic fact that the value of a good falls as it becomes more abundant. The curve for ISO New England, by contrast, begins at a high price level but then suddenly drops (vertically) to a low but positive floor price level at a threshold reserve level. The downward-sloping demand curve approach of ISO New England, the New York ISO, and PJM leads to less volatile capacity prices than would a vertical demand curve approach, as the former has price gradually change with reserve margins while the latter has price suddenly change at the threshold reserve level.52 50 LSEs can opt out of PJM’s mandatory capacity market and self-supply all of their capacity on stringent terms that are cost-effective for only very large LSEs with very large resource portfolios. 51 Federal Energy Regulatory Commission, 143 FERC ¶61,090 (2013), PJM Interconnection LLC, Order Conditionally Accepting in Part, and Rejecting In Part Proposed Tariff Provisions, Subject to Conditions, May 2, 2013. 52 ISO New England and the New England Power Pool (NEPOOL) recently replaced its fixed capacity requirement (i.e., vertical demand curve) with an administratively determined, downward-sloping demand curve. See FERC, ISO New England Inc., New England Power Pool Participants Committee, Docket No. ER14-1639-000, April 1, 2014. 25 Figure 4 Sample Demand Curves for PJM, New York ISO, and ISO NE, 2016/2017 Delivery53 The maximum price when capacity falls short of the target is defined in all three RTOs in relation to the Cost of New Entry (CONE). CONE is defined as the annualized capacity cost of a new peaking plant. As illustrated in Figure 4, all three RTOs have set their maximum prices in the neighborhood of $200 per kW-year for the 2016/17 delivery year. All three RTOs set the maximum price at 1.5 times their estimates of CONE net of revenue earned from the energy and ancillary services markets as adjusted for forced outage rates (adjusted net CONE). The downward-sloping segments of the demand curves for New York ISO and PJM are defined by their reserve targets and various multiples of CONE, again adjusted for forced outage rates. In traditionally regulated regions, “capacity” is defined differently than in RTO regions. While “capacity” in RTO regions is steel in the ground or qualifying demand-side resources, “capacity” in traditionally regulated regions is a call option that gives the buyer the right to purchase power at specified terms under particular conditions. The prices of capacity in traditionally regulated regions are therefore determined by buyers’ demand for optional power that meets their reliability needs and by the cost and availability of sellers’ resources to meet their needs. The capacity development process in traditionally regulated regions provides incentives for resource investment to the extent that sales of capacity add to the recovery of investment costs. 53 Federal Energy Regulatory Commission, Centralized Capacity Market Design Elements, Commission Staff Report, Docket No. AD13-7-000, August 23, 2013, Figure 2, p.6. 26 Although the word “chopper” can refer to motorcycles as well as helicopters, one would not suppose that the price of one kind of “chopper” bears any resemblance to the price of the other kind of “chopper.” Similarly, because “capacity” is such a very different product in traditionally regulated regions than in RTO regions, and because the determinants of demand and supply for “capacity” are so different in these two types of regions, one should not expect that the prices of capacity are comparable between the two types of regions. 4.2.3. Market Power Mitigation Market power can be exercised in capacity markets if and when participants can profitably manipulate capacity prices. A capacity seller that has resources in excess of its own requirements may be able to profit from withholding capacity from the market and thereby raising the prices at which they sell their excess. A capacity buyer that is deficient in resources may be able to profit by procuring subsidized resources and thereby reducing the market prices at which they must purchase resources to cure their deficiency; though some controversy has been generated by the strangeness of accusing participants of wrongdoing for procuring resources that meet their own needs. Market power can be problematic in short-term capacity markets because of the insensitivity of supply to price: most resources that will be available a few years from now have already been built or at least have significant sunk costs that cannot be avoided by a decision to withhold capacity from the market; so, except in cases of retirement, the resources will be available regardless of the capacity price. The consequence of this insensitivity is that small changes in supply can have large impacts on short-term capacity prices. The price impacts are particularly great if the RTO’s administratively determined demand curve is vertical, which means that the RTO requires a particular quantity of capacity regardless of price. Consequently, New York ISO and PJM have attempted to mitigate the price impacts of supply changes by incorporating a downward-slope into their administratively determined demand curves, which has the effect of reducing the profitability of exercising market power. The RTOs have a variety of tests for market power. The tests for supplier market power variously seek to determine if there will be a shortage without the capacity of certain suppliers, or if certain combinations of suppliers have large market shares, or if a supplier’s costs differ substantially from its offer price. The tests for buyer market power require that a supplier justify a low bid (below a minimum offer price) with cost data under certain circumstances. The three eastern RTOs have similar market power mitigation rules. PJM, for example, has explicit rules that define the must-offer requirement for capacity, structural market power, and offer caps based on the marginal cost of capacity. These rules incorporate flexible criteria for competitive offers by new entrants or by entrants that may have an incentive to exercise monopsony power. Demand-side resources and Energy Efficiency resources may be offered directly into the capacity auctions and receive the clearing price without mitigation. Market power mitigation can affect resource investments in a few ways. First, supply-side mitigation can induce capacity owners to offer all their capacity to the market, thereby increasing supply; though by holding down capacity prices, it might discourage new investment. 27 Second, buyer-side mitigation can dissuade resource-deficient LSEs from investing in new capacity; though by increasing capacity prices, it might encourage new investment by others. Third, market power mitigation may be implemented in ways that support or undermine state renewable resource policies or state resource planning processes. Market power is not a problem in long-term capacity markets – that is, for capacity that is to be available more than a few years from the present – because buyers have the ability to build (or subscribe to) new capacity in this longer time frame. Consequently, capacity market power evaluation and mitigation occurs only in the context of RTOs’ short-term capacity markets. 4.2.4. Strengths and Weaknesses of the Price Determination Methods The main strength of the centralized capacity market price determination processes of the eastern RTOs lies in price transparency and liquidity of the markets. In addition, the downwardsloping demand curves used by New York ISO and PJM mitigate the volatility of capacity market clearing prices that are experienced under a vertical demand curve design, which also helps mitigate market power. The price-setting methods of the eastern RTOs have several important weaknesses. First, the assumptions and estimates that underlie the determination of the demand curves are critical to price determination; and yet these assumptions and estimates, including those about the slope of the demand curve and CONE, have often been controversial. Moreover, some of the controversial estimates must be revised regularly, leading to regular repetition of the controversies. The controversies can be keen because the assumptions and estimates can have significant effects on the amounts of capacity procured and the prices of capacity. Second, the physical and design characteristics of the eastern RTO’s capacity markets can make them prone to exercises of market power. This susceptibility to market power arises from the physical limits that transmission places on capacity deliverability among zones and the steepness of the demand curves. Third, in addition to fostering market power, transmission deliverability issues lead to zonal capacity markets of relatively small size, which decreases liquidity and increases the volatility of the zonal capacity prices. Furthermore, power system configurations change over time, even from year to year; so that the definitions of capacity zones must change over time. The consequence of the decreased liquidity, increased volatility, and shifting zonal definitions is to increase the uncertainty about future capacity prices and thereby increase the cost of capacity investment. Fourth, the eastern RTOs try to treat heterogeneous resources as a homogeneous product. Consequently, they struggle, with limited success, to find ways to give comparable treatment to resources (e.g., fossil-fuel versus intermittent versus demand-side, existing versus planned, unlimited dispatchability versus limited dispatchability versus no dispatchability, flexible versus inflexible) that have very different operating and availability characteristics. Fifth, the RTOs’ centralized capacity markets make unrealistic assumptions about the relationship of capacity prices to capacity cost. The basic assumption is that the capacity prices should generally reflect the levelized cost of pure peaking capacity, which is why CONE is 28 defined as the levelized annualized capacity cost of a new peaking plant. In addition to the various problems with the ways that CONE is quantified and annualized, however, there is little or no reason for anyone to offer capacity to the market at CONE or even at their own levelized annualized cost. Existing resources will always offer capacity at their opportunity cost of remaining in service, which is zero for most plants and a low figure for most of the rest. New resources will offer capacity at prices that depend upon their forecasts of market conditions over their whole lives, without the unrealistic assumption (explicit in levelization) that they must recover the same amount of capacity cost in every year. In the words of one prominent advocate of capacity markets, …the investor’s projections of capacity prices for the remaining life of the new unit are vastly more important that the clearing price in the initial year in which the resource is cleared… [I]nvestors’ decisions [to invest] will be principally governed by either expectations of future capacity prices beyond the initial auction or on a bilateral forward capacity contract that locks in a number of years of capacity revenues… For example, assume a unit has a net CONE over 30 years equal to $90 per kW-Year. It is unlikely that the new resource would be offered in a forward procurement market at close to $90 per kW-Year. If the investor has already made the decision to enter based on its projections of capacity prices over the next 30 years or the fact that it has signed a long-term bilateral contract, then the investor would likely submit offers well below $90 per kW-Year to ensure its offer clears. If the investor has not already made the decision to enter and expects that capacity prices are likely to fluctuate below $90 per kW-Year over the next 30 years (as surplus capacity levels rise and fall), then the investor would likely submit its offer at a price much higher than $90 per kW-Year.54 But in spite of the fact that no resource can reasonably be expected to base its offer price on CONE or even on its own levelized costs, the RTOs’ capacity demand curves and their buyerside market power mitigation are both based upon CONE. 4.3. Traditionally Regulated Regions In traditionally regulated regions, resource requirements are determined by a combination of NERC, the relevant regional reliability entities, federal and state requirements, and utilities implementation of good utility practices. Each LSE (possibly in the context of a state proceeding) forecasts its resources and loads and determines whether it needs additional resources to meet it capacity obligation or whether it has excess resources to offer to other parties. If it needs additional resources, it either invests in generation capacity on its own, invests in joint ownership arrangements with other LSEs, enters into competitively determined 54 Post-Technical Conference Comments of Potomac Economics Ltd. New York ISO Market Monitoring Unit, Centralized Capacity Markets in Regional Transmission Organizations and Independent System Operators, before the Federal Energy Regulatory Commission, Docket No. AD13-7-000, January 8, 2014, p. 19. 29 bilateral contracts to purchase the output of capacity from other parties, or undertakes some combination of the foregoing options. The decision about whether to “build” or “buy” comes down to an economic assessment of the options, which will also include consideration of fuel mix, capacity lumpiness, expected rate of load growth, and a host of other factors including regulatory policy (such as those regarding competitive bidding requirements, renewable resources and environmental regulations). When the “buy” option is pursued, the utility typically issues a request for proposals to supply the needed incremental capacity, which also typically includes energy. Contract length can vary from only a couple of years to very long term (e.g., 20 years). Bids from interested suppliers are evaluated on terms that go beyond price, including deliverability, generator characteristics, and technology type. Thus acquisition of capacity in bilateral markets is subject to competition, and the prices of capacity in bilateral markets are determined by a competitive process. The main strengths of capacity price determination in traditionally regulated regions are that prices depend upon the real demands of buyers and upon the actually available supplies of sellers, and that prices are determined through a competitive process, albeit often scrutinized by state utility regulators. These capacity prices reflect real market value. Because the capacity markets in traditionally regulated regions are not limited to a homogeneous capacity product, buyers and sellers can take into account the particular operational and other characteristics of the particular resources involved; and the capacity price can reflect those characteristics. The main weakness of the price-setting process in traditionally regulated regions is that prices are not transparent, so it is possible that the most efficient capacity trades are sometimes unrecognized. Related to the lack of transparency is a relative lack of liquidity, which can cause prices to be volatile. The impacts of volatility on customers are muted, however, since the volatility affects only incremental capacity needs while the bulk of the utility’s capacity costs are fixed based on prior years’ commitments. 5. RESOURCE OUTCOMES How well has each capacity market approach done at assuring reliability at least cost? Are there significant differences among the approaches in their reliability outcomes? Are there significant differences among the approaches in their costs? This section assesses resource outcomes primarily in terms of reliability outcomes, reliability indicators (like reserve margins), achievement of public policy goals (like expansion of renewable resources), capacity prices, and consumer costs. 5.1. Reliability Power system reliability is measured by the MWh magnitude, the geographic extent, and the time duration of customer service outages. In principle, reliability should be the gold standard for judging resource outcomes: adequate resources should result in relatively reliable power systems, while inadequate resources should result in relatively unreliable power systems. In practice, however, the overwhelming majority of customer service outages are due to failure of local, low-voltage distribution systems, usually caused by adverse weather conditions; and most 30 of the remaining outages are caused by bulk power transmission failures. By contrast, our concern in this report is with those outages that occur at the transmission level due to insufficient capacity resources, which are a tiny percentage of all outages experienced by customers. Unfortunately, it is not possible to easily separate outages due to insufficient capacity resources from those due to other causes. While transmission failures due to lightning or trees are among these other causes, system operator error is the most common cause. Operator errors include:  overestimation of generator availability;  overestimation of generators’ dynamic reactive output;  inability to visualize events over the entire power system;  failure to ensure that system operation was within safe limits;  lack of coordination on system protection;  ineffective communication between system operators and resource operators;  lack of “safety nets;” and  inadequate training of personnel. Consider, for example, the following major North American outages of the past half century:55 55  November 9, 1965, Northeastern U.S. System operators lacked adequate information about system conditions, and were unaware of the operating set point of the relay that started the cascading outages.  July 13, 1977, New York City. Lightning struck and tripped out two transmission lines on a common tower, and separated New York City from the surrounding power systems. A bent contact on a relay contributed to the collapse.  December 22, 1982, West Coast. High winds knocked over a transmission tower, which fell onto an adjacent tower, taking out of service the two transmission lines held up by the two towers. Contingency planning failed to consider the power flows caused by this event. A control signal was delayed by a communications failure. System operators lacked sufficient information to identify appropriate action.  July 2-3, 1996, West Coast. Due to a vegetation maintenance failure, a sagging transmission line contacted a tree and tripped out. A protective relay on a parallel line incorrectly tripped out.  August 10, 1996, West Coast. Due to high temperatures, three transmission lines sagged, contacted untrimmed trees, and trip out. Because of insufficient contingency JTF 031119 Report, Chapter 6. 31 planning, system operators were unaware, for the next hour, that the system was in an insecure state.  June 25, 1998, Ontario and North Central U.S. Lightning struck and tripped out two 345-kV transmission lines, which led to overloading of lower-voltage lines. Relays took these lower-voltage lines out of service. This cascading removal of lines from service eventually separated the entire northern MAPP Region was separated from the Eastern Interconnection.  July 1999, Northeastern U.S. PJM’s load was 5,000 MW higher than forecast, resulting in a loads exceeding available resources.  August 14, 2003, Northeastern U.S and Ontario. Beginning with a vegetation maintenance failure, MISO system operators were literally out to lunch. They lacked adequate system information, failed to operate the system within secure limits, failed to identify emergency conditions, failed to communicate with neighboring systems, lacked sufficient regional and interregional visibility of the power system, had a dysfunctional SCADA/EMS system, lacked adequate backup for their SCADA/EMS system, and suffered inadequate operator training.  September 8, 2011, Southern California. A 500-kilovolt east-west transmission line in California, the Hassayampa-North Gila line, failed because a technician skipped several steps as he tried to isolate some transmission equipment for testing. His actions led to a short circuit and a shutdown of the line. The blackout’s scope could have been limited if operators had been trained to intentionally cut off some areas to prevent a cascade. As with the Eastern blackout in 2003, however, system operators had poor knowledge of what was happening in neighboring systems, which prevented them from taking proper action until it was too late.56 Thus, with the exception of the 1999 Northeast blackout, the major North American outages of the past half century have not been due to inadequate resources. Consequently, reliability statistics reveal little about resource adequacy. 5.2. Resource Additions and Reserves The most relevant measure of resource adequacy is arguably reserve margins, which are the amounts by which resources exceed loads. The patterns of resource additions over time directly affect reserve margins and indicate whether investment has been sufficient and will be sufficient to maintain reserve margins. Consequently, this section presents statistics on capacity additions and reserve margins. 56 FERC and NERC Staffs, Arizona-Southern California Outages on September 8, 2011, Causes and Recommendations, April 2012. 32 5.2.1. Overview of U.S. Capacity Resources Figure 5 shows how total resources (including generation and demand-side resources), total annual peak loads, and reserve margins have changed (and are projected to change) for the entire U.S. over the period 2002-2017. The figure looks at summer peaks rather than winter peaks because, for the U.S. as a whole, summer peaks are about 8% higher than winter peaks; so summer reliability issues tend to be more critical than winter reliability issues. 57 The figure shows that the U.S. summer resource capacity has exceeded net internal demand by approximately 15% or more over the last 12 years and is projected to continue that relationship through at least 2017. Resource additions and reserve margins are the consequence of many factors, of which market design is only one. Other major factors include, for example, regulatory rules, legal requirements for renewable resources, fuel prices, and general economic conditions. Nonetheless, this section looks at traditionally regulated regions separately from RTO regions in an effort to see if different market structures lead to any obvious differences in resource addition or reserve margin outcomes. 57 Perhaps the one exception to that has been the most recent 2013/2014 winter, which was characterized by the “polar vortex” described in various parts of this report. 33 Reserve Margin (%) 25% 1,000,000 900,000 800,000 700,000 600,000 500,000 400,000 300,000 200,000 100,000 0 20% 15% 10% 5% 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 0% Capacity (MW) Figure 5 Resources, Peak Loads, and Reserve Margins for the U.S., Summer 2002-201758 Reserve Margin (%) Net Internal Demand (MW) Summer Capacity (MW) 5.2.2. Traditionally Regulated Regions with Vertically Integrated Utilities Figure 6 shows summer peak reserve margins for three traditionally regulated regions, namely Florida (FRCC), the southeastern U.S. (SERC), and the western interconnection excluding California (WECC). Years through 2012 are actual historical results, while years beginning in 2013 are forecasts. Overall, reserve margins in WECC have been most volatile; SERC’s margins have been consistently higher than FRCC’s margins; and SERC’s margins have been consistently above the 10% level. In all cases, the reserve margins do not reflect demand-side capacity. 58 U.S. Energy Information Administration, Form EIA-411, Coordinated Bulk Power Supply and Demand Program Report. http://www.eia.gov/electricity/data.cfm#demand, “Summer net internal demand, capacity resources, and capacity margins, 2001-2011 actual” and “Summer net internal demand, capacity resources, and capacity margins, 2011 actual, 2012-2016 projected” (Form EIA-411). “Net Internal Demand” represents the system demand that is planned by the electric power industry`s reliability authority and is equal to Internal Demand less Direct Control Load Management and Interruptible Demand. “Summer Capacity” represents utility- and non-utility-owned generating capacity that exists (as part of the historical record) or is in various stages of planning or construction (as part of the project capacity), less inoperable capacity, plus planned capacity purchases from other resources, less planned capacity sales. “Cap Margin” represents the amount of unused available capability of an electric power system at peak load as a percentage of capacity resources. These definitions apply to all subsequent figures. The Summer peak period is defined to begin on June 1 and extends through September 30. 34 Figure 6 Summer Peak Reserve Margins (%) of Non-RTO Regions59 40% Reserve Margin (%) 35% 30% 25% FRCC 20% SERC 15% WECC 10% 5% 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 0% In FRCC, reserve margins bounced around throughout most of the past decade, hit a low of 6% in 2009, and have been (and are projected to be) in the 14% to 27% range since 2010. The low reserves occurred in 2009 because, in spite of the 2008-2009 financial crisis, FRCC loads hit a high in that year at the same time that there happened to be resource retirements. The stability of reserve margins from 2011 onward reflects the actual and forecast stability of total capacity and peak loads beginning in 2011. In SERC, reserve margins were in the 10% to 16% range through 2008. Since the onset of the financial crisis of 2008-2009, reserve margins have been (and are projected to be) of 20% to 35%. This occurred, in part, because SERC’s peak load during the years 2005-2009 was consistently over 186 GW, but has been (and is forecast to be) only about 160 GW from 2010 onward. Not coincidentally, SERC’s capacity peaked in 2009, since which time retirements reduced capacity by 20%, with future capacity forecast to be flat. In WECC (excluding California), reserve margins generally have been maintained at or above the NERC reference level with the exception of 2012, when capacity reached its low point while peak load jumped 9%. The recent and forecast jump in reserve margins is due largely to an 59 WECC data are obtained from Energy Information Administration, Table 8.8.A, “Summer Net Internal Demand, Capacity Resources, and Capacity Margins by North American Electric Reliability Assessment Areas 2002-2012, Actual”, and Table 8.8.B, “Summer Net Internal Demand, Capacity Resources, and Capacity Margins by North American Electric Reliability Corporation Assessment Areas, 2012 Actual, 2013-2017 Projected”, both available at http://www.eia.gov/electricity/annual/. The original source is Form EIA-411. Projected reserve margins for FRCC and SERC were obtained from North American Electric Reliability Corporation, 2013 Long-Term Resource Assessment, December 2013. 35 expected 35 GW increase in supply-side capacity, split about evenly between gas-fired, wind, and solar generation. 5.2.3. Centralized Markets of Regional Transmission Operators Figure 7 shows that the RTOs shared a common reserve margin trend up until the wake of the financial crisis of 2008-2009, since which time their paths have diverged. The RTOs generally had excess reserves in 2002 that were left over from the investment binge of the late 1990s, when electricity industry deregulation gave investors some of the irrational exuberance for generation investments as they had for stock market investments. Rising loads in California, ERCOT, and SPP helped to bring down their reserve margins in the years through 2006, while their capacity was basically flat. The years 2006-2009 saw rising reserve margins as loads generally declined (with Texas being the exception) while capacity was flat to rising. Since 2009, the RTOs’ reserve margins have taken (and are forecast to take) divergent paths that are best explained by looking at each RTO. In California, since the shortages of the 2000-2001 crisis, reserve margins generally have been maintained at or above the NERC and CPUC’s target reference level of 15% and are anticipated to remain well above the target over the next four years. A significant driver in the increase in reserve margin over the next few years is California’s renewable portfolio standard (RPS), which requires that 33% of the state’s annual electrical energy be obtained from renewable resources by 2020. On the other hand, environmental restrictions on once-through cooled generation60 are expected to force retirement of about 13,000 MW of older capacity by 2020. Another major reduction in non-renewable resource capacity will occur later this decade with the retirement of the 2,100 MW San Onofre nuclear plant. The combination of these factors is forecast to reduce reserves in 2017 and beyond. To deal with retirements as well as the reliability and resource adequacy issues that will accompany the substantial growth of intermittent generation, the California ISO proposed a special compensation mechanism for critical generation resources that might otherwise retire. FERC rejected California ISO’s special compensation mechanism as “an ineffective out-ofmarket solution” and has requested that the California ISO instead develop a market-based mechanism to achieve its resource adequacy goals.61 60 Once-through cooled generation uses water's cooling capacity only a single time before discharging the water as waste. It thus withdraws and promptly returns large volumes of warmed water. 61 Federal Energy Regulatory Commission, Order On Tariff Revisions, 142 FERC ¶ 61,248, Docket No. ER13-550-000, March 29, 2013. 36 Figure 7 Summer Peak Reserve Margins (%) of RTO Regions62 40% Reserve Margin (%) 35% 30% CA ISO 25% ERCOT ISO NE 20% MISO 15% NY ISO 10% PJM 5% SPP 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 0% In ERCOT, reserve margins have been eroding since 2002, when they were well above 25%. Reserve margins are expected to remain well below the NERC target reference level of 13.75% for the next several years. According to NERC: The depleting Reserve Margin in ERCOT is due to generation resource additions not having kept pace with the higher than normal load growth experienced in recent years. The generation market in ERCOT is unregulated and generators 62 Historical reserve margins for ERCOT, MISO, PJM, and SPP were obtained from Energy Information Administration, Table 8.8.A, “Summer Net Internal Demand, Capacity Resources, and Capacity Margins by North American Electric Reliability Assessment Areas 2002-2012, Actual”, http://www.eia.gov/electricity/annual/. Projected reserve margins for ERCOT, MISO, PJM, and SPP are “Anticipated Reserve Margins” obtained from North American Electric Reliability Corporation, 2013 Long-Term Reliability Assessment, December 2013, pp. 20, 123, 142, and 149. California ISO reserve margins are based on “California Peak Load History, 1998 – 2013”, http://www.caiso.com/Documents/CaliforniaISOPeakLoadHistory.pdf. California ISO capacity for 2005-2013 is from “Cal ISO Summer Load and Resource Assessment Report” various years, obtained at https://www.caiso.com/planning/Pages/ReportsBulletins/Default.aspx. California ISO projected reserve margins for 2014-2017 are from California Public Utility Commission, CPUC Briefing Paper: A Review of Current Issues with Long-Term Resource Adequacy, February 20, 2013, Appendix B: 2012 LTPP Base Scenario (2012-2022), obtained at http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M040/K642/40642804.PDF. Historical reserve margins for ISO New England are based on ISO New England, 2013 CELT Report, obtained at http://www.isone.com/trans/celt/report/. Projected reserve margins for ISO New England are “Anticipated Reserve Margins” from North American Electric Reliability Corporation, 2013 Long-Term Reliability Assessment, p. 91. Historical reserve margins for New York ISO were obtained from “NY ISO Load & Capacity Data”, various years. Projected reserve margins for New York ISO are “Anticipated Reserve Margins” obtained from North American Electric Reliability Corporation, 2013 Long-Term Reliability Assessment, December 2013, p. 101. 37 make resource decisions based on market dynamics. Generation investors state that a combination of lack of long-term contracting with buyers, low market heat rates, and low gas prices are hindering decisions to build new generation. For its part, the PUCT and ERCOT are working through to study, and facilitate revisions to, market protocols and pricing rules to bolster the reserve margin. To incent new generator construction, improvements such as increases in system-wide Energy Offer caps, rising of Energy Offer floors, and adjustments to Emergency Response Service to include distributed generator participation, are among the results so far. Several proposed initiatives focus on DR resources, such as revising market rules to stimulate greater participation of weather-sensitive loads in the Emergency Response Service program. The PUCT has directed ERCOT to draft rules for incorporation of an interim energy market funding solution called the Operating Reserve Demand Curve (ORDC). The PUCT will continue efforts regarding possible setting of a mandated reserve margin level in the ERCOT region.63 In New England, reserve margins have consistently exceeded the target of 15% over the past decade, and are expected to fall to the target level by 2017. The forecast for 2017 appears to be a statistical quirk, however, due to exclusion of Capacity Supply Obligations (CSOs) in ISO New England’s forecast of capacity in 2017. Correcting for that statistical quirk, reserve margins will likely remain in the neighborhood of 20%. In MISO, there is forecast to be a dramatic decline in reserve margins for MISO from 23% in 2010 down to 6.3% in 2017, well below the target level of 14.2%. Peak demand has already fallen and is forecast to remain relatively flat over the next several years, while capacity has fallen more sharply as generating plant is retired, particularly in response to new environmental rules. According to NERC: Based on MISO’s current awareness of projected retirements and the resource plans of its membership, Planning Reserve Margins will erode over the course of the next couple of years and will not meet the 14.2 percent requirement. The impacts of environmental regulations and economic factors contribute to a potential shortfall of 6,750 MW, or a 7.0 percent Anticipated Reserve Margin… by summer 2016. Accordingly, existing-certain resources are projected to be reduced by 10,382 MW due to retirement and suspended operation.64 In New York, just over half of the investment during the period 2000-2012 occurred in the three years 2004–2006. Since 2002, reserve margins have generally remained above the NERC reference level of 15%, with the exception of 2010. The New York ISO’s own installed reserve margin target is 17% (set by the NYSRC) and the forecast indicates the region will exceed that 63 North American Electric Reliability Corporation, 2013 Long-Term Resource Assessment, December 2013, p. 150. Note that low market heat rates and low gas prices lead to low prices for electrical energy. 64 North American Electric Reliability Corporation, 2013 Long-Term Resource Assessment, December 2013, p. 54. 38 target through at least 2017. The stable reserve margins projected over the next few years are due to moderate expected growth in peak load coupled with few planned generator retirements. However, retirement of the Indian Point Nuclear Power Plant, in 2015 or thereafter, would lead to immediate violations of the NYSRC’s reserve margin criteria. In PJM, reserve margins have generally held above PJM’s planning reserve target of about 15.5%, but are projected to decline below this level after 2014. With peak demand growth expected at just over 1% per year and demand-side management resource capacity expected to remain fairly constant, the principal driver of the decay in reserve margins is the significant retirement of fossil-fired generation – 13,000 MW (or about 7% of the existing capacity) composed of 9,700 MW of coal plants, 2,000 MW of gas-fired plants, and 1,300 MW of oil-fired generation.65 In SPP, reserve margins during the mid-2000s dropped below the planning reserve target of 13.6%, but since have climbed to acceptable levels, rising abruptly in 2012 to 27%. SPP’s reserve margins are expected to remain above the NERC reference target for the foreseeable future as a result of moderate load growth and a modest 400 MW of retirements. 66 5.2.4. Summary of Findings Baseline forecasts usually reflect an assumption that the future world will be normal – which it usually is on average, but which it often is not in individual cases. With the exceptions of ERCOT and MISO, whose reserve margins are projected to decline to levels well below the NERC target margins, the NERC regional reliability entities and the RTOs project adequate reserve margins for the foreseeable future. However, reserve margins in all regions are projected to decline over the next decade, primarily because the capacity of the large number of retirements of coal-fired plants will exceed the capacity of the new plants (gas-fired and renewable for the most part) coming into service. 5.3. Resource Mix The mix of capacity resources can have major impacts on power system reliability, for several reasons. First, supplies of particular resources can become constrained due to weather conditions, transportation bottlenecks (as happened with natural gas supplies and coal supplies this past winter of 2013-2014), or production problems; so over-reliance upon a single resource technology can have adverse reliability or cost impacts. Second, demand-side capacity resources are an innovation that is not entirely out of the testing stage: in the long run, such resources may or may not prove as reliable as traditional supply-side resources. Third, intermittent renewable resources (i.e., wind and solar) pose new challenges for maintaining power system security; and these challenges will grow disproportionately quickly as the market share of these resources grows. 65 North American Electric Reliability Corporation, 2013 Long-Term Resource Assessment, December 2013, p. 124. 66 North American Electric Reliability Corporation, 2013 Long-Term Resource Assessment, December 2013, p. 143. 39 5.3.1. Overview of the U.S. Resource Capacity Mix Figure 8 shows how, for the entire U.S., the resource capacity mix has evolved over the period 2000-2012 and is forecast to evolve over the period 2013-2017. The figure shows that, for the 2000-2017 period, coal and gas switch first and second places: coal drops from a 39% market share to a 26% market share, while gas rises from a 27% market share to a 42% market share. The other resource technologies have market shares that are generally 10% or less. The shares of nuclear, hydroelectric, petroleum, and pumped storage all gradually decline over the period, even though all but petroleum have more GWs of capacity in 2017 than in 2000. Meanwhile, the shares of wind and solar, which were near 0% in 2000, rise to 6% and 1%, respectively, in 2017. The overall story, then, is that gas, wind, and solar have been rising stars while petroleum is fading out. Figure 8 U.S. Resource Mix, Shares of Summer Capacity, 2000-201767 45% 40% Natural Gas 35% Coal 30% Nuclear 25% Hydroelectric 20% Wind 15% Petroleum 10% Pumped Storage Solar 5% Other 2017 2016 2015 2014 2013 2012 2011 2010 2009 2008 2007 2006 2005 2004 2003 2002 2001 2000 0% The changing market shares reflect changing economics and politics. Coal faces growing and particularly costly environmental restrictions, the uncertainty of greenhouse gas-related costs, and well organized environmental opposition, all of which make traditional coal-fired investments less attractive. Natural gas, by contrast, has enjoyed technological progress that has substantially increased potential gas supplies and significantly reduced gas costs, thus 67 U.S. Energy Information Administration, “Planned generating capacity additions from new generators, by energy source, 2011-2015 December 12, 2013”, Table 4.5; and “Existing Capacity by Energy Source, by producer, by state back to 2000”, existcapacity_annual.xls, both obtained at http://www.eia.gov/electricity/data.cfm#gencapacity. 40 making gas-fired investments more attractive.68 Petroleum has continued its long-term decline as oil-fired generation is generally replaced by cheaper and cleaner gas-fired generation. The progress made by wind and solar resources has partly been due to technological improvements that have reduced their costs but has mostly been due to substantial subsidies. 69 5.3.2. Overview of Regional Capacity Resources Figure 9 illustrates the fuel mix across the regions of the U.S. in 2011. The central (Mountain, West North Central, East North Central, South Atlantic, East South Central) and southeastern regions rely heavily on coal, whereas the northeastern regions (New England and Middle Atlantic) rely more heavily on a combination of nuclear and natural gas. The West South Central region relies heavily on a combination of coal and natural gas, while hydro and natural gas dominate in the Pacific Contiguous region. Despite the abundance of coal and natural gas resources in the U.S., the fuel diversity displayed in Figure 9 may soon be altered significantly. The nation’s generation fleet is experiencing a dramatic shift, spurred by low natural gas prices and a suite of new environmental regulations that are particularly adverse to coal use. This shift is expected to occur largely over the next five to seven years as natural gas prices are expected to remain low and recent environmental regulations are likely to accelerate the retirement of a significant portion of the nation’s coalfired power plants. In addition, pending regulations would prohibit the construction of new coal-fired power plants that do not have carbon capture and sequestration capabilities, effectively phasing out the use of new coal generation as a future resource in the United States.70 5.3.3. Renewable Energy Resources Because of their relatively high costs, wind, solar, geothermal, and biomass resource investments have been heavily dependent upon public policy, particularly federal and state income tax subsidies and renewable portfolio mandates. As the subsidies have grown and (particularly) as the mandates have become more stringent, investment in these technologies has increased. Since 2000, this investment has been substantial and been concentrated on wind power. Renewable energy capacity grew at a 4.8% per annum compound rate from 2000 through 2012, nearly doubling during the period. In 2012, renewable power resources provided 56% of generating capacity additions, and constituted 14% of U.S. installed capacity 68 The abundance of natural gas in the U.S. has created a strong lobby for increasing U.S. natural gas exports, which would be profitable due to high overseas natural gas prices and could improve the energy security of U.S. allies. Significant export of natural gas would put upward pressure on gas prices in the U.S. and could eventually make investment in gas-based capacity less economic. 69 Section 5.6 reviews the cost trends that influence the resource mix. 70 U.S. Environmental Protection Agency, Standards of Performance for Greenhouse Gas Emissions for New Stationary Sources: Electric Utility Generating Units, Notice of Proposed Rulemaking, 77 Fed. Reg. 22,392, April 13, 2012. 41 and 12% of generated electrical energy. Of the renewable resource generation in 2012, 55% was hydroelectric, 28% was wind, 11% was biomass, and solar and geothermal provided 3% each.71 While wind, biomass, and geothermal generation will continue to grow, solar power is projected to have the largest future growth, in percentage terms, between now and 2040. Figure 9 U.S. Regional Fuel Diversity, 201172 The leading states for solar power investments (photovoltaic (PV) and concentrating solar power (CSP)) are mostly in the southwestern and southern states that have the best solar exposure. Similarly, the leading states for geothermal and hydroelectric resources tend to be those with the best geological conditions for these resources. But these are merely tendencies. What particularly drives the locations of investments are the public policies that support renewable power.73 Not surprisingly, the ten states with the largest amounts of installed 71 U.S. Department of Energy, Renewable Energy and Energy Efficiency, 2012 Renewable Energy Data Book, October 2013, pp. 17-18, http://www.nrel.gov/docs/fy14osti/60197.pdf. 72 U.S. House of Representatives, The Committee on Energy and Commerce, Memorandum, Subcommittee On Energy and Power Hearing, March 4, 2013, Appendix, p. 4. 73 U.S. Department of Energy, Renewable Energy and Energy Efficiency, 2012 Renewable Energy Data Book, October 2013, p. 31. Original sources: EIA, GEA, LBNL, SEIA/GTM, Larry Sherwood/IREC. 42 renewable capacity in 2012 are also states with renewable portfolio standards that mandate large amounts of installed renewable capacity by 2016. Table 2 lists these states, which together had about 61% of the total RE capacity in the country in 2012. Aside from Texas, the top five states rank high because of their significant hydro capacity. Texas, by contrast, rates high because of its huge investment in wind and solar, which can be attributed largely to the state’s favorable geographic location. Table 2 Relationships Between RPS Requirements and Renewable Investment Top Ten Renewable Resource States in 2012, by Total RE74 State 2011 Installed Capacity RE Target Intermediate Target 2012 Installed RE Total % of Installed Capacity 2012 Installed Wind + PV % of Installed Capacity WA 30,507 15% by 2020 3% by 2012 24,342 80% 2,827 9% CA 68,295 33% by 2020 20% by 2014 22,508 33% 8,102 12% TX 109,179 5,880 MW by 2015 (8.8% of 2012 Peak) 5256 MW by 2013 13,517 12% 12,354 11% 5% by 2011 11,845 81% 3210 22% No interim goals 7,003 18% 1818 5% Large Utils - 25% by 2025; Small Utils 10%; Smallest Utils - 5% Overall target of 7% of incremental MWh by 2015 (equivalent to about 0.5673 of total load) OR 14,535 NY 39,629 IA 15,288 105 MW fixed (1.3% of 2012 Peak) No interim goals 5,280 35% 5,134 34% AZ 27,043 10.55% by 2025 No interim goals 4,108 15% 1,345 5% OK 21,824 15% by 2015 No interim goals 3,699 17% 2,998 14% Al 32,577 No explicit RPS 3,917 11% 1 < 1% IL 43,830 25% by 2025 3,803 9% 3,611 8% No interim goals 6% by 2012 Wind power has become a large share of RE, and the rankings in Table 2 reflect the rise of wind power. Back in 2000, when total U.S. wind capacity was only 2,578 MW, California had nearly two-thirds of the capacity. In 2012, when capacity was about 60,000 MW, Texas had taken the top spot and wind capacity was much more evenly spread among states. The southeastern U.S. is nearly devoid of wind resources, which is partly a reflection of the relatively poor wind conditions in that part of the country.75 Iowa and Illinois now appear in the top five states ranked on total installed wind and PV capacity, which is a reflection of the relatively good 74 Installed capacity data are from U.S. Energy Information Administration, “Existing capacity by energy source, by producer, by state back to 2000,” http://www.eia.gov/electricity/data.cfm#gencapacity. RE Target and Intermediate Target information are from Database of State Incentives for Renewable Energy (DESIRE), obtained at http://www.dsireusa.org/. RE capacity data are from U.S. Department of Energy, Energy Efficiency & Renewable Energy, 2012 Renewable Energy Data Book, http://www.nrel.gov/docs/fy14osti/60197.pdf. 75 American Wind Energy Association, AWEA U.S. Wind Industry Third Quarter 2013 Market Report, October 31, 2013, p. 5. 43 conditions for location of wind installations. The top ten states possess about 69% of wind and solar capacity in the country. Washington, Oregon, and California are all among the top five RE states because of their significant hydro capacity. Alabama likewise makes it into the top ten for overall RE because of its abundant hydro capacity, though it would rank among the bottom of the states on the basis of its wind and solar capacity. 5.3.4. Demand-Side Resources Figure 10 summarizes the actual peak load reductions achieved through energy efficiency measures and load management over the period 2002 to 2012. During this eleven year period, peak load reductions achieved through demand-side management programs have nearly doubled, with energy efficiency growing at an 8.0% annual rate and load management growing at a 3.6% annual rate. These demand side resources were 2.5% of supply-side capacity in 2002 and 4.0% of supply-side capacity in 2012. Figure 10 provides a projection of peak load reductions due to demand-side management programs over the period 2012 to 2023. The growth rates of demand resources are projected to fall to a 3.6% annual rate for energy efficiency and a 2.3% annual rate for load management. Nonetheless, this NERC projection has energy efficiency and load management programs together accounting for nearly 15% of non-coincident total internal demand for the peak summer season of 2023. 44 Figure 10 Estimated Demand-Side Management Load Reductions by Program Type, 2002-201276 Actual Peak Load Reduction (MW) 60,000 50,000 40,000 30,000 20,000 10,000 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Energy Efficiency Load Management Projected Peak Load Reduction (MW) Figure 11 Projected Demand-Side Management Load Reductions by Program Type, 2012-202377 60,000 50,000 40,000 30,000 20,000 10,000 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 Energy Efficiency Load Management 76 Energy Information Administration, Electric Power Annual, 2012, Table 10.1, Demand-Side Management Annual Effects by Program Category, 2002 to 2012, obtained at http://www.eia.gov/electricity/annual/. 77 Projections based on NERC, 2013 Long-Term Resource Assessment, pp. 8-9. NERC projects that available energy efficiency will increase by 11.9 GW and load management will increase by 3.3 GW between 2014 and 2023. This translates to a compound annual growth rates of 3% for energy efficiency and 2% for load management. 45 In the eastern RTO capacity market auctions, large quantities of demand-side resources have been offered and cleared, which has caused the RTOs’ capacity prices to drop substantially. In PJM, for example, about one-third of new capacity obtained through its Base Residual Auctions has been from demand-side resources. Unfortunately, in at least some RTO markets, demand-side resources provide a lower quality of capacity than do supply-side resources. Andy Ott of PJM explains the limitations of the demand-side resources available to PJM: …almost all demand resources are specifying two-hour notice requirements and emergency-only status[,] resulting in over 12,000 MW of demand responsebased capacity resources having very similar operational characteristics. PJM has experienced a… marked difference in operational comparability between generation and demand response given the notice requirements and emergencyonly status of most of the demand response resources. These significant differences… limits [sic] the usefulness of today’s demand response resources to PJM operators in preventing the triggering of emergency conditions and then responding to emergency conditions once they have materialized. Unfortunately, to date, those demand response resources do not offer more diverse operational characteristics even though they are physically capable of doing so. PJM believes demand response resources can be available in a manner largely comparable to generation and that market rules should be adapted to provide the necessary incentives.78 FERC has recently approved PJM’s request to place a cap on the quantity of capacity procured from demand response that has limited availability.79 PJM requested the procurement cap because it believes that substituting limited-availability demand response for higher-availability resources has suppressed auction clearing prices and has impeded its ability to procure capacity to ensure grid reliability. The plain implications are that the security value of demand-side resources can be less than that of supply-side resources, and that more costly incentives may be required to get performance from demand-side resources than are needed to get similar performance from supply-side resources. Furthermore, there is some question about the durability of demand-side resources. For example, some entities that offered demand-side resources in ISO New England’s initial capacity auction did not continue to offer part of that capacity in subsequent auctions. Instead, they ultimately purchased supply-side capacity to cover about a quarter of their capacity 78 Statement Of Andrew Ott, Executive Vice President – Markets, PJM Interconnection, L.L.C., Centralized Capacity Markets in Regional Transmission Organizations and Independent System Operators, before the Federal Energy Regulatory Commission, Docket No. AD13-7-000, September 9, 2013. 79 FERC, 146 FERC ¶ 61,052, Order on Proposed Tariff Changes, Docket No. ER14-504-000, January 30, 2014. 46 commitments for the 2013/14 Commitment Period. If demand-side resources do not possess longevity comparable to that of supply-side resources, they are not as reliable or as valuable as supply-side resources. 5.3.5. Summary Table 3 and Table 4 show the fuel mixes of each of the regions in 2011. The tables show that coal is still king in the nation’s coal-rich old industrial regions (MRO, RFC, MISO, and PJM), while natural gas is the technology of choice elsewhere in the country. The second and third ranking fuel choices vary regionally and across the RTOs based on the advantages afforded a particular fuel and technology by virtue of geographic endowments or proximity to fuel sources. For example, hydro places second in CAISO and WECC (which have substantial and ubiquitous elevation drops), and wind ranks third in MRO and ERCOT (which have the best conditions for wind production). Nuclear continues to have a strong presence in three reliability regions – NPCC, RFC, and SERC, which include ISO NE, MISO, New York ISO, and PJM. Petroleum has a significant market share only in the old industrial states of the northeast (NPCC, including ISO NE and New York ISO). Solar has yet to make any significant gains in any region of the country but Florida. Figure 12 and Figure 13 summarize net summer generation capacity in 2000 and 2012 by fuel types for the non-RTO regions compared to the RTOs. The figures show the change over the past decade in the degree of penetration of renewables (solar thermal and PV and wind), as well as shifts (generally reductions) in reliance on more traditional fuels such as coal and natural gas. The wind output in the central and west central regions of the country (served by ERCOT, MISO, SPP, and non-RTO states) is part of what is driving the significant expansion of the transmission grid that will enable that output to be transported to the eastern load pockets. Table 3 Fuel Mixes of the Regional Reliability Organization Regions, 201280 Fuel Type Coal Hydro Natural or Other Gas Nuclear Petroleum Solar Wind Other FRCC MRO NPCC RFC SERC WECC 17.1% 41.6% 7.0% 46.2% 33.5% 16.0% 0.1% 4.5% 12.6% 3.1% 8.2% 26.7% 57.3% 24.3% 44.0% 30.0% 38.4% 40.1% 7.1% 7.6% 13.2% 11.6% 15.0% 4.6% 15.2% 4.4% 17.5% 4.6% 1.9% 0.4% 0.1% 0.0% 0.1% 0.2% 0.1% 1.2% 0.0% 16.4% 3.2% 2.6% 1.2% 8.8% 3.2% 1.1% 2.2% 1.6% 1.8% 2.3% 80 Derived from U.S. Energy Information Administration, Form EIA-860 for 2012 Final, Release Date October 10, 2013, obtained at http://www.eia.gov/electricity/data/eia860/. Texas Reliability Entity and Southwest Power Pool Regional Entity are not presented because of the significant intersection with ERCOT and SWPP as RTOs presented in Table 4. 47 Table 4 Fuel Mixes of the RTO Regions, 201281 Fuel Type Coal CA ISO ERCOT ISO NE MISO NY ISO PJM SPP 0.5% 21.1% 7.2% 45.2% 6.8% 40.7% 31.6% Hydro 19.6% 0.6% 10.5% 4.4% 14.5% 5.1% 3.2% Natural or Other Gas 58.8% 61.3% 40.4% 28.0% 47.2% 29.9% 49.5% Nuclear 6.2% 4.5% 13.2% 10.6% 13.3% 13.8% 6.6% Petroleum 0.3% 0.5% 19.0% 2.5% 10.7% 6.4% 2.4% Solar 1.6% 0.1% 0.1% 0.0% 0.1% 0.2% 0.1% Wind 7.7% 11.1% 2.2% 8.5% 4.1% 1.6% 5.6% Other 5.2% 0.8% 7.3% 0.7% 3.2% 2.3% 0.9% For non-RTO regions of the country, coal capacity has not changed over the past decade; but its share has declined significantly and is now second in importance to gas-fired capacity. Solar technology has not entered the fuel mix in non-RTO regions, but wind has now a small but significant presence. 81 Derived from U.S. Energy Information Administration, Form EIA-860 for 2012 Final, Release Date October 10, 2013, obtained at http://www.eia.gov/electricity/data/eia860/ . 48 Figure 12 Net Summer Generating Capacity (MW) by Non-RTO and RTO Regions, 200082 120,000 100,000 80,000 60,000 40,000 20,000 Reg Non- CA ISO ERCOT ISONE MISO NYISO PJM RTO Coal Geo Hydro NG Nuke Other Otr Bio Otr Gas Petrol Pumped Strg Solar Thm & PV Wind Wood SPP Figure 13 Net Summer Generating Capacity (MW) by Non-RTO and RTO Regions, 201283 120,000 100,000 80,000 60,000 40,000 20,000 0 Reg Non- CA ISO ERCOT ISONE RTO Geo Other Pumped Strg Coal Nuke Petrol MISO NYISO Hydro Otr Bio Solar Thm & PV PJM SPP NG Otr Gas Wind 82 Energy Information Administration, Existing capacity by energy source, by producer, by state back to 2000 obtained at http://www.eia.gov/electricity/data.cfm, Original source: Form EIA-860, Annual Electric Generator Report, 2000. 83 Derived from U.S. Energy Information Administration, Form EIA-860 for 2012 Final, Release Date October 10, 2013, obtained at http://www.eia.gov/electricity/data/eia860/. 49 In nearly every RTO region, gas-fired generation capacity has at least doubled over the past decade. The effect of a combination of state renewable portfolio standards and geographical advantages have allowed wind capacity to increase from almost nothing in 2000 to relative significance in 2011 in all RTO regions outside of the northeast. 5.4. Net Revenue Analysis To assess the market incentives for capacity investments, several RTOs estimate the profits that would have been earned in their markets by certain generation technologies. Specifically, the RTOs’ analyses quantify each technology’s net revenues – that is, the amount by which a generator’s revenues from the sale of energy and ancillary services can be expected to exceed its variable production costs. This excess is available to cover a generator’s fixed costs (including return on investment). If this excess covers only a part of a generator’s fixed costs, the generator will lose money unless the shortfall can be covered by the generator’s capacity market revenues. In principle, it is economic for net revenues to be deficient persistently when the market has surplus capacity because, in such a situation, the price mechanism should not signal a need for additional capacity. It is also economic for net revenues to be excessive persistently when the market is short on capacity because, in such a situation, the price mechanism should signal a need for additional capacity. Net revenue analysis may yield findings that temporarily contradict these principles due to temporary fluctuations in market or economic conditions, such as may occur because of weather or unusually high or low forced outages of resources. If net revenue analysis yields findings that persistently contradict these principles, there is a market design problem. Table 5 and Table 6 summarize the estimated net revenue for new combustion turbines and combined cycle units in RTOs for each of the years 2005 through 2012. The figures in these tables, which were developed by the RTOs or their independent market monitors, represent the revenues that would have been earned in the energy and ancillary services markets (and in capacity markets, where those exist) by a hypothetical combustion turbine or combined cycle unit operating in each year. The rightmost column presents the PJM Independent Market Monitor’s estimate of capacity costs levelized (in nominal dollars) over twenty years.84 For both natural gas plant types, net revenues on an RTO-wide basis were generally insufficient to cover levelized costs, with the exception of New York in 2005-2007 for combined cycle plants. The summer peak reserve margins shown in Figure 7 imply some need for new resource capacity during the boom years of 2005-2007; so this insufficiency implies a failure to signal shortages in these years. 84 For simplicity, we used PJM’s estimates of CONE as bases for comparison even though the other RTOs estimate CONE for their respective markets. The estimates vary among RTOs for a variety of reasons. Use of the other RTOs’ CONE estimates would lead to similar general conclusions about the insufficiency of revenues to support entry. 50 Table 5 Comparison of Net Revenue for Combustion Turbine Gas Plant ($ per MW-month)85 Year 2005 2006 2007 2008 2009 2010 2011 2012 CAISO 4,333 5,083 4,917 4,417 3,750 4,083 ERCOT 3,333 7,583 3,667 3,750 9,167 2,083 ISO NE 2,500 2,333 2,000 MISO NYISO PJM 2,250 2,250 2,333 1,917 3,167 4,167 5,667 5,250 3,833 3,333 1,750 833 1,250 4,083 4,250 4,833 7,667 7,167 4,500 Levelized Cost 6,000 6,667 7,583 10,333 10,750 10,917 9,250 9,417 Table 6 Comparison of Net Revenue for Combined Cycle Gas Plant ($ per MW-month)86 Year 2005 2006 2007 2008 2009 2010 2011 2012 CAISO 7,500 10,000 3,250 2,750 1,917 2,750 ERCOT 7,083 12,500 5,000 6,250 11,667 3,333 ISO NE 3,333 3,167 2,917 MISO NYISO PJM 3,167 3,000 3,333 10,250 10,417 13,333 10,833 5,000 6,833 5,167 7,667 3,417 4,167 8,417 8,667 8,667 12,333 13,000 10,833 Levelized Cost 7,833 8,250 12,000 14,250 14,417 14,583 12,833 12,917 85 The RTOs assume that combustion turbine units have heat rates between 10,250 and 10,500 MMBtu per MWh. See California ISO, 2011 Annual Report on Market Issues & Performance, Department of Market Monitoring, April 2012; California ISO, 2012 Annual Report on Market Issues & Performance, Department of Market Monitoring, April 2013; Potomac Economics Ltd., 2012 State of the Market Report for the ERCOT Wholesale Electricity Market, June 2013, Figures 63 and 64, pp. 76 & 77; The Brattle Group, 2013 Offer Review Trigger Price Study, October 2013; Potomac Economics, 2012 State of the Market Report, for MISO, Figure 6, p. 10; Potomac Economics, New York ISO 2008 State of the Market Report, Figures 10 and 11, pp. 36-37; Potomac Economics, New York ISO 2012 State of the Market Report, Figures A-14 and A-15, p. A-22; and Monitoring Analytics, 2008 and 2012 State of the Market Report for PJM, Net Revenue Analysis sections. The New York figures are averages of values for the Hudson Valley and Capital Zones for 2004-2007, and averages for the Hudson Valley, Capital, and West Zones for 2008-2012. 20year levelized cost figures are from Monitoring Analytics, 2008 and 2012 State of the Market Report for PJM, obtained at http://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2012.shtml. 86 The RTOs assume that combined cycle units have heat rates between 7,000 and 7,500 MMBtu per MWh. Sources are the same as listed in the preceding footnote. 51 Although the net revenues presented in Table 5 and Table 6 represent overall regional averages, net revenues actually vary by zones within each RTO. Hence, in some RTOs, there are some zones, particularly in metropolitan and industrial regions with relatively high loads, in which net revenues have been high enough to cover levelized costs.87 Furthermore, investors’ expectations of a plant’s profitability are shaped by many factors and may not depend on achieving an annual return on levelized cost over the plant’s long life. Consequently, the information in these tables should be interpreted to mean that the RTOs’ market prices have generally not been sufficient to cover levelized costs. 5.5. Price Trends Capacity market prices have been volatile over the past decade and have remained volatile even as some of those RTOs – ISO NE, PJM, and New York ISO – launched centralized forward capacity markets in the mid-2000s. Figure 14 summarizes the capacity market prices for selected zones of the Eastern RTOs over delivery years 2010-2016. The selected zones – New York City and Long Island zones for the New York ISO and Southwest Mid-Atlantic Area Council for PJM – are included to illustrate the price separation among capacity markets that can occur when transmission constrains deliverability of capacity among zones. Both MISO and New York ISO’s prices are set for a delivery year only one year ahead, while ISO New England and PJM conduct auctions that set capacity prices for a delivery year from three to five years in the future. 87 For example, in PJM in 2013, a new combined cycle plant would have earned sufficient revenues from the energy, ancillary services, and capacity markets to cover levelized costs in seven if PJM’s twenty zones. Nonetheless, a new combustion turbine would not have earned sufficient revenues in 2013 to cover levelized costs in any of the twenty zones. 52 Figure 14 Capacity Market Prices: RTO-Wide and Selected Zones ($/MW-month)88 $12,000 Capacity Price ($/MW-month) $10,000 $8,000 $6,000 $4,000 $2,000 $2010 2011 2012 2013 2014 2015 2016 2010/2011 2011/2012 2012/2013 2013/2014 2014/2015 2015/2016 2016/2017 ISO NE NY ISO - ROS NY ISO - NYC NY ISO - LI MISO PJM-RTO PJM-SWMAAC 5.6. Cost Trends Figure 15 summarizes the levelized cost of energy for selected renewable and conventional generating technologies over the period 2008 to 2013. Costs for 2008-2011 are reduced by various tax subsidies, while costs for 2012-2013 do not consider such subsidies. The figure shows that gas combustion turbines have the highest levelized costs, of over $200 per MWh, which occurs because they are used for peaking purposes in relatively few hours of each year. Solar thermal technologies have the second highest costs, of about $150 per MWh, while solar photovoltaic (PV) technologies had the third highest costs until their costs 88 New York ISO prices include Rest of State (ROS), New York City (NYC), and Long Island (LI). PJM prices include RTO and SW Mid-Atlantic Area Council. The horizontal axis displays calendar years (on top) and delivery years (on bottom). Prices for New York ISO and MISO correspond to averages based on calendar year, while prices for ISO NE and PJM are based on a twelve-month delivery year that straddles two calendar years. 53 significantly dropped in 2013 with improvements in utility-scale technologies. In favorable locations, utility-scale solar technologies are now competitive on a levelized cost basis with IGCC, nuclear, and coal plants, all of which have costs in the neighborhood of $100 per MWh. The least costly technologies, at around $75 per MWh, are gas combined cycle plants and wind turbines. Note that the solar and wind costs, in addition to benefiting from targeted subsidies, do not include the costs of the backup generation and other services necessary to handle intermittency. Solar and wind capacity may not be available when they are needed most. In addition, levelized costs of intermittent resources and those of conventional technologies, such as combustion turbines, are not comparable unless they are adjusted according to equivalent availability factors. Figure 15 Levelized Cost of Generation Technologies, 2008-2013 (2011 $/MWh)89 300 250 Gas Combustion Turbine Solar Thermal 200 IGCC Nuclear 150 Coal 100 Solar PV Gas Combined Cycle 50 Wind 0 2008 2009 2010 2011 2012 2013 Figure 16 shows the capital costs per MW of capacity of selected renewable and conventional generating technologies over the period 2008 to 2013. Nuclear plants are the most expensive, 89 Lazard Ltd., Levelized Cost of Energy Analysis, Version 2 (June 2008) through Version 7 (June 2013), Table Levelized Cost of Energy Comparison. For years 2008 through 2011, reported costs account for subsidies: Production Tax Credit, investment tax credit, and accelerated depreciation where applicable. Costs for 2012 and 2013 are expressed without subsidies. Costs assume a 20- to 40- year economic life, 40% tax rate, and 5- to 40year tax life. For alternative technologies, the assumed capital structure is 30% debt at 8% interest, 50% tax equity at an 8.5% annual return, and 20% common equity at a 12% annual return. The capital structure for traditional technologies is assumed 60% debt at 8% interest and, 40% equity at a 12% return. Coal and gas prices vary by year. All costs are expressed in 2011 dollars. 54 rising from $5,900 up to $7,500 per MW during the period. IGCC, coal, and solar thermal plants have an intermediate level of expense, beginning around $3,500 per MW in 2008 and rising in 2013 to $4,300 in the case of solar thermal and to $6,800 in the case of IGCC. The cost of utility-scale solar PV fell from $3,100 to $1,900 while the cost of wind varied around $2,000 per MW. Gas combined cycle and gas combustion turbine plants are the least expensive plants, with costs around $1,000 per MW. The levelized cost for each technology is determined based on an assumption about the technology’s capacity factor, which generally corresponds to the high end of its likely utilization range. For example, the Energy Information Administration (EIA) assumes a 30% percent capacity factor for simple combustion turbines (conventional or advanced technology) that are typically used for peak load duty cycles. In contrast, the duty cycle for intermittent renewable resources such as wind and solar is dependent on the weather or solar cycle and so will not necessarily correspond to operator-dispatched duty cycles. Consequently, levelized costs of intermittent resources are not directly comparable to those for other technologies (even when the average annual capacity factor may be similar) and therefore direct comparisons made on the basis of Figure 15 should be made with extreme caution. 55 Figure 16 Capital Costs of Generation Technologies, 2008-2013 (2011 $/MW)90 8,000 7,000 Capital Cost ($/MW) 6,000 5,000 4,000 3,000 2,000 1,000 2008 Solar PV - Thin Techonolgy IGCC 2009 2010 Solar Thermal Nuclear 2011 Wind Coal 2012 2013 Gas Combustion Turbine Gas Combined Cycle Given their relatively low capital and operating costs, it is apparent why gas combined cycle plants are the technology of choice. The other technologies are attractive for their low costs under special conditions (e.g., solar in sunny climates, gas combustion turbines for peaking purposes), for their environmental benefits (e.g., wind), or for fuel diversity. 5.7. Observations The centralized capacity markets were created to provide resource owners with steady income streams, thereby helping encourage generation investment and delays in generation retirements. Thus far, however, the centralized capacity markets have provided rather volatile income streams, as is evident from the price histories shown in Figure 14; and reasonable questions may be raised about how generators with thirty- to fifty-year lives can gain financial solace from capacity markets that look only a few years into the future. 90 Id. 56 Further investment uncertainties arise from the fact that capacity is not a real product: consumers want the energy that capacity provides; and system operators want the operating reserves and other ancillary services that capacity provides; but nobody wants capacity for the mere pleasure of having steel in the ground. In traditional markets, capacity has implicitly been a call option that gives the capacity purchaser the right to obtain electrical energy from the capacity seller under particular circumstances. In the centralized markets, by contrast, “capacity” is a product that gives no right to the purchaser except to meet whatever capacity obligation is determined by the RTO. Having little anchor in physics or economics, both the definition of “capacity” and the constructions of capacity market demand curves have been and will continue to be subject to perpetual controversy. When RTOs suddenly change their minds about the extent to which demand-side resources can count as capacity, or the extent to which intermittent wind resources can count as capacity, or whether certain capacity will be subject to minimum offer pricing restrictions, or when congestion will change the definitions of capacity pricing zones, capacity prices can change substantially.91 The different ways that RTOs set the capacity demand curves likewise have large impacts on capacity prices. Because definitions of “capacity” and capacity demand curves are artificial, they will change over time and thereby have a limited ability to offer steady income streams. 5.7.1. Relationships of Market Design to Resource Adequacy Figure 17 and Figure 18 present forecast summer reserve margins for traditionally regulated and RTO regions, respectively. For each region, the bars indicate NERC forecasts of anticipated planning reserve margins for 2014, 2018, and 2023; and the black horizontal lines indicate required reserve margins (i.e., NERC “Reference Reserve Margin Levels”). The figures show that planning reserve margins are projected to decline significantly across much of the country between 2014 and 2023, with the largest percentage declines in MISO, ERCOT, SERC-E, NPCC-NE, SERC-W, MRO-MAPP, and SERC-N. These declines reflect the expectation that large quantities of coal-fired capacity will be retired as a result of increasingly more stringent and costly environmental compliance rules. MISO and ERCOT appear to be most affected, with projected planning reserve margins falling below 5%, while SERC-E is a close third with projected reserve margins below 10%. There appears to be no section of the country 91 For example, PJM eliminated the Interruptible Load for Reliability (ILR) demand-side product effective for the 2012/2013 Delivery Year. ILR resources were not eligible to offer capacity in PJM’s capacity market because, instead of providing the three-year advance commitment required for capacity resources, ILR allowed certification in as little as three months prior to the delivery year. For demand response resources procured under the ILR program to continue to serve as capacity resources after the program’s elimination, they had to comply with the rules governing PJM’s capacity market. To compensate for the elimination of short-term demand-response resources due to the discontinuance of ILR, short-term demand-side resources were accommodated by removing 2.5% of the reliability requirement from the demand curve in the BRA for auctions close to the actual delivery year. The movement of significant demand-side capacity into the BRA coupled with the reliability requirement reduction led to significant drop in the market prices for capacity in the 2012/2013 BRA and subsequent years. 57 that escapes the impact of retirements and the increasing role played by renewable technologies under state RPS mandates. Figure 17 Forecast Summer Reserve Margins for Traditionally Regulated Regions92 60% 50% 40% 30% 20% 10% 0% -10% 2014 2018 92 2023 North American Electric Reliability Corporation, 2013 Long-Term Reliability Assessment, December 2013, pp. 1517. 58 Figure 18 Forecast Summer Reserve Margins for RTO Regions93 60% 50% 40% 30% 20% 10% 0% -10% 2014 2018 2023 The most striking difference between the traditional and RTO regions is that the traditional regions have higher forecast reserve margins than the RTO regions in all forecast years. The respective simple averages for the three years 2014, 2018, and 2023 are: traditional regions, 31.9%, 25.2%, and 17.2%; RTO regions, 23.8%, 17.4%, and 13.7%. A plausible explanation for this result is that the relatively stable regulated returns on investment in traditionally regulated regions tends to induce ample resource investment in these regions, while competition in the RTO regions tends to induce cost-cutting that drives reserve margins to be closer to requirements. Consistent with this difference in forecast reserve margins and with the similarity in reserve requirements among regions, none of the traditionally regulated regions are forecast to violate reserve requirements in 2014 or 2018, while ERCOT is forecast to violate requirements in both years and MISO is forecast to violate requirements in 2018. Half the traditionally regulated regions and half the RTO regions are forecast to violate requirements in 2023; but because of the conservative assumptions underlying the forecasts, most of these violations are unlikely to occur as there is still ample time to take remedial action. For example, IRP processes in traditionally regulated markets typically project reserves as though no previously uncommitted resource additions will be made even though these IRP processes typically require building or procuring wholesale capacity well in advance of the capacity need. 93 Id. 59 Capacity market design seems to have a modest impact on reserves. A statistical test of the difference between the average reserve margins for traditional and RTO markets finds that these markets differ at the 10% level of significance, with the RTO market average lower than the traditional market average. There is thus some statistical evidence that RTO markets tend to have lower reserve margins than traditional regulated markets, but this does not explain the significant difference between the forecast reserve margins of the two market groups. 5.7.2. Assessment of Resource Diversity Effects The shift away from coal-fired generation to natural gas and renewables may create problems for grid stability and reliability. The intermittency of wind and solar generation will have to be backed by a reasonable combination of baseload, intermediate, and peaking generation – and possibly storage, if it becomes cost-effective in the future – with fast start, load following and ramping characteristics. Public policy that influences long-term generation planning must be guided by an appreciation of the benefits of fuel diversity for maintaining a reliable power supply. This dramatic shift away from the use of coal has significant implications for the diversity of the U.S. electricity generation portfolio, for electricity suppliers, and for their customers. As the U.S. incorporates greater amounts of intermittent renewable resources into the nation’s generation mix, the need to maintain diversity in the baseload power portfolio is critical. 5.7.3. Long-Term Contracting and Generation Investment Long-term bilateral power purchase contracts are crucial to the functioning of electricity markets. They give price stability and certainty to both buyers and sellers, thereby helping manage risk and thereby supporting new resource development. Prudent business practice would have utilities and LSEs procure most of their capacity resources through ownership or bilateral contracts, with short-term markets serving as the venue for rectifying inevitable mismatches between resources and obligation. Arbitrage should cause bilateral contract prices to reflect risk-adjusted expectations of short-term market prices. In jurisdictions with traditional regulation of electric utilities, which includes states within RTO regions as well as those in non-RTO regions, just about all electricity is procured either through self-supply or through competitive wholesale market solicitations that result in bilateral arrangements. In restructured regions, the short-term timeframe of the RTOs’ centralized capacity markets seems far too short in duration (one to three years) to provide new capitalintensive capacity with the revenue guarantees necessary to support favorable financing. The eastern RTOs have tried to address this issue by instituting forward locational capacity markets that nonetheless fail to provide the long-term assurance of revenues which would be needed to adequately support generation investments. 5.7.4. Natural Gas Deliverability Power systems increasingly rely on natural gas-fired capacity for a number of reasons, including low gas prices. This increase has exposed power systems and LSEs in much of the country to 60 the risk that sufficient gas may not be available to meet power system needs during periods of very high seasonal demand, under other stressed system conditions, or when facing contingencies associated with natural gas supply/transportation system infrastructure. Gas deliverability constraints, rather than gas production constraints, are the concern. Deliverability threatens the reliability of power systems due to the limited capacity of the pipelines used to transport gas, coupled with the “just-in-time” nature of the resource as used by power generators. The reliability risks partly arise from the differences between gas and electric system operational requirements and market mechanisms. Gas transportation systems are designed to meet the needs of firm (non-interruptible) contract holders (historically comprised mostly of Local Distribution Companies) that draw gas more slowly and predictably from pipelines than do generators. Uncertainties in generation availability, commitment, and dispatch make it risky for any one independent generator to choose long-term firm contracts for gas delivery. On the other hand, as non-firm gas delivery customers, gas-fired generators can be interrupted when pipelines are unable to fully meet gas demand, which leads to electric reliability issues. Utilities with fleets of gas-fired generators have the economy-of-scale advantage of being able to commit to firm (non-interruptible) gas transportation because they can depend upon the average availability, commitment, and dispatch of the fleet to be more stable than availability, commitment, and dispatch of any single generator. The risks created by the power industry participants that rely on non-firm gas transportation were made apparent by the exceptionally cold “polar vortex” that gripped much of the Midwest in the winter of 2013/2014. The combination of record-high winter peak electricity loads, gas deliverability constraints, and volatile gas prices caused wholesale price spikes as generators and other gas consumers without firm gas transportation commitments struggled to procure natural gas. In anticipation of such conditions, FERC decided in November 2013 to allow interstate natural gas pipeline and electric system operators to share nonpublic operational information to facilitate natural gas and power reliability.94 The growing interdependence of the natural gas supply and bulk power supply system has focused attention of participants and policy makers in both the gas and electric industries on ways to improve natural gas-electricity interactions and coordination. Efforts in some regions of the country (the northeast in particular) and at the national level (at FERC and by NERC) have been made to analyze the problems and to consider fuel supply and transportation adequacy as a formal part of electric reliability assessments and short- and long-term planning.95 On the electric side of the relationship, some changes to RTOs’ energy, ancillary service and capacity 94 Federal Energy Regulatory Commission, Order No. 787, Communication of Operational Information Between Natural Gas Pipelines and Electric Transmission Operators, 145 FERC ¶61,134, 18 CFR Parts 38 and 284, Docket No. RM13-17-000, November 22, 2013. 95 For example, see North American Electric Reliability Corporation, 2013 Special Reliability Assessment: Accommodating an Increased Dependence on Natural Gas for Electric Power: Phase II, A Vulnerability and Scenario Assessment for the North American Bulk Power System, May 2013; and Federal Energy Regulatory Commission Staff, Gas-Electric Coordination Quarterly Report to the Commission, Docket No. AD12-12-000, September 19, 2013; and PJM, LLC, Gas Electric Senior Task Force Problem Statement, 2013. 61 market rules have already been made and others likely will have to be made to accommodate the challenges created by gas pipeline inadequacy for non-firm users and the “just-in-time” nature of gas acquisition for power production that can at certain times severely limit operating and planning reserve margins. 5.7.5. Plant Retirements As shown in Figure 19, about 23,000 MW of coal-fired generating capacity retired between 2005 and 2013, and another 37,300 MW is expected to retire over the next decade, mostly during the next four years. The retirements are due to a combination of increasingly stringent environmental regulations, an aging coal fleet, more efficient new generating technologies, low gas prices, modest demand growth, and policies favoring renewable resources. Figure 19 Actual and Projected Coal-Fired Capacity Retirements, 2005 to 202696 16,000 14,000 Capacity (MW) 12,000 10,000 8,000 6,000 4,000 2,000 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2020 2022 2025 2026 0 Figure 20 shows that coal-fired generation retirements are concentrated in the Midwest and mid-Atlantic states. 96 SourceWatch, Table 2, http://www.sourcewatch.org/index.php/Coal_plant_retirements. 62 Figure 20 Reported Coal-fired Generator Retirements – 2012 to 201697 5.7.6. Reliability Issues Arising from Intermittent Resources Wind- and solar-powered resources provide power only when the wind blows or the sun shines. The resulting intermittency of their power output creates system control problems that are costly to resolve. As intermittent resources’ share of total capacity increases, there must be other generation readily available to back up these resources when they do not provide power. Making matters more difficult is the fact that subsidized wind and solar resources can depress energy prices. Consequently, at the same time that intermittent resources create a need for fossil fuel-fired generation to compensate for their intermittency, they reduce the energy revenues that fossil fuel-fired generation can hope to receive. The recent and ongoing experience in Germany provides some lessons about the impacts of and unintended consequences of relatively rapid adoption of high penetration levels of wind and solar resources. As should be expected, the significant market shares of wind and solar resources in Germany has driven down German wholesale market prices substantially and created problems in maintaining grid reliability in the face of large swings in intermittent power output, leading Germany’s power system operators to curtail renewable energy production 21% of all hours (1,800 hours) in 2011 and 82% of all hours (7,200 hours) in 2012.98 The 97 http://www.eia.gov/todayinenergy/detail.cfm?id=7290 98 “Germany’s Retail Tariffs Now Decoupled from Wholesale Rates, ”The Electricity Journal, November 2013, 26(9): 7-8. Also see Bundesnetzagentur, Report on the State of the Grid-based Energy Supply in Winter 2011/2012, May 3, 2012. 63 depressed German energy market prices have put resource adequacy at risk because some dispatchable resources, such as natural gas fired turbines, are less economically viable. 6. PROSPECTIVE RELIABILITY IMPACTS OF EVOLVING TECHNOLOGY Advances in power system technologies will have three general sorts of impacts on power system security and reliability. First, they will increase actual or effective resource capacities. Second, they will improve the control capabilities of power system operators. Third, they will add to the complexities of controlling power systems. 6.1. Increases in Resource Capacities As a general rule, technological improvements reduce the real (inflation-adjusted) costs of generation resources and improve the technical efficiencies (output per input) of those resources. Such improvements will therefore increase the supply of resources available at any given cost level. Improvements in storage technologies – in terms of both costs and physical capabilities – will improve the competitiveness of intermittent generation technologies. Whether these improvements will be sufficient to make these technologies competitive (without subsidies) with conventional technologies is not yet knowable. Improvements in transmission technologies – such as those that increase the carrying capacities of lines or reduce the costs of transmission equipment – reduce the costs of delivering power from resources to consumers. Such improvements will increase power systems’ effective resource capacity. 6.2. Improvements in Power System Control Power systems have already derived significant efficiency benefits from the development of regional joint commitment and dispatch of resources and the computerization of this commitment and dispatch. These benefits have come in two major forms: substitution of cheaper resources for more expensive resources; and reduced reserve requirements. Further improvements in computer technologies and further regionalization of power system control promise additional benefits. So-called “smart grid” technologies promise to allow extension of efficient commitment and dispatch to micro-resources, particularly demand resources and certain distributed generation resources. The effect of such an extension would be to increase the resource capacity that is available to the power system 6.3. Complications to Power System Control Increasing penetration of intermittent generation resources has created and will create significant security and reliability challenges. The fundamental problem is that electricity supply and demand must be in balance at every moment in time, but the electric power fueled by the wind and the sun changes erratically and unpredictably from moment to moment. Until 64 electrical energy storage becomes sufficiently cheap, power system operators will need to protect the security of power systems through various costly mechanisms for compensating for the intermittency of wind and solar resources. These mechanisms are dispatchable resources with high ramping rates that can, on very short notice, provide the capacity that intermittent resources cannot provide. 7. DIRECTIONS FOR FUTURE REFORM OF METHODS FOR ASSURING ADEQUATE CAPACITY There are two basic sets of issues in assuring capacity adequacy. The first concerns defining the capacity mandate:  How much capacity is needed?  What qualifies as capacity?  What types of capacity should be built? The second set of issues concerns how to best meet the mandate:  Who should be responsible for meeting the mandate?  How can markets most efficiently be organized to meet the mandate? Reform proposals address various aspects of the foregoing questions. This section begins with proposals to reform the capacity mandate, and then looks at proposals to reform the means of meeting the mandate. 7.1. Reforms in Defining the Capacity Mandate 7.1.1. Reformed Pricing of Operating Reserves William Hogan of Harvard University has for many years promoted the idea of allowing operating reserve prices to signal real-time capacity shortages.99 The basic notion is to reward resources’ actual performance; but Hogan would partially displace capacity markets with enhanced operating reserve markets. Operating reserves do, after all, have the primary purpose of ensuring power system security. Hogan even claims that “There is a possibility that an operating reserve demand curve by itself would provide sufficient incentives to support resource adequacy without further developing forward capacity markets.”100 Key elements of Hogan’s approach include the following:  Operating reserve curves would be downward-sloping, indicating that the marginal value of operating reserves falls as the quantity of operating reserves increases. 99 For a recent statement of his position on this issue, see W.W. Hogan, “Electricity Scarcity Pricing Through Operating Reserves,” Economics of Energy & Environmental Policy 2(2): 65-86, IAEE, September 2013. 100 Id., p. 72. 65  Operating reserve curves would be based upon the value of lost load and the probability of load curtailment. When there is involuntary load curtailment, the price of operating reserves would equal the value of lost load minus energy rents. When there is not involuntary load curtailment, the price of operating reserves would equal the value of lost load times the probability of load curtailment, minus energy rents.  Operating reserve curves would be administratively determined, such as by the system operator. Hogan’s approach gives efficient real-time price signals, setting operating reserve prices at very high levels when power system security is at risk. These efficient price signals are not limited to operating reserves, however. Because many resources can offer both energy and reserves, arbitrage will cause energy prices to become very high when operating reserve prices become very high. The very high prices for operating reserves and energy would reward resources for being available when they are needed most and would send price signals consistent with the need for voluntary load reductions. MISO has implemented a version of Hogan’s approach that has a downward-sloping operating reserve curve, with a price based upon the value of lost load when reserves are near zero, and with a price that falls according to estimates of how the probability of load curtailment falls as reserves rise to the level of the reserve requirement. The operating reserve price does not depend upon energy rents as Hogan proposes, however, but is instead depends upon other factors, including the per-MWh average cost of committing and running a peaking unit for an hour.101 Hogan provides a theoretically correct approach to the problem of pricing operating reserves; but this approach will not solve the capacity adequacy problem because it will not provide sufficient revenues to cover capacity costs in systems with one-event-in-ten-year reliability standards. As Roy Shanker has noted: …while modifications to the energy market such as the operating reserve demand curve… would obviously improve real time energy price signals, they would not obviate the need for a capacity market. Indeed, the best solutions are where more efficient real time energy prices are combined with an appropriate capacity mechanism.102 Reformed pricing of operating reserves would improve the efficiency of day-ahead and realtime markets, and it might help recover some capacity costs that would not otherwise be recovered; but it would not provide sufficient capacity cost recovery. 101 MISO, FERC Electric Tariff, Schedule 28, “Demand Curves for Operating Reserve, Regulating and Spinning Reserve, and Regulating Reserve,” November 19, 2013. 102 Comments of Roy J. Shanker Ph. D., Centralized Capacity Markets in Regional Transmission Organizations and Independent System Operators, before the Federal Energy Regulatory Commission, Docket No. AD13-7-000, September 11, 2013, pp. 3-4. 66 7.1.2. Capacity Compensation Based on Actual Resource Availability Power system security depends upon the resources that are actually available during peak periods rather than upon the resources that promise to be available. In particular, security is not enhanced by a generator that is out of service when reserve margins are tight, nor by demand-side resources that do not reduce load when needed. Consequently, capacity prices should reward actual availability both as a matter of efficiency (to encourage resources to be available when needed) and as a matter of fairness (so that consumers are paying only for capacity that has real value and not for capacity that does not perform). Accordingly, Peter Cramton (of the University of Maryland) and Steven Stoft have proposed to reward only that “capacity that contributes to reliability as demonstrated by its performance during hours in which there is a shortage of operating reserves.”103 Key elements of their proposal include the following:  Capacity prices should be based upon actual capacity rather than bid capacity. This prevents the withholding of capacity that would allow an exercise of market power.  Capacity payments should be based upon the capacity price net of the actual energy rents rather than the theoretical energy rents of a benchmark peaking unit.104 “Energy rents” are the energy and reserve profits of the benchmark peaking unit during the hours when there is an operating reserve shortage. Setting capacity payments in this manner would improve the price signal and would also limit the exercise of market power. Joseph Bowring, the Independent Market Monitor for PJM, has concerns similar to those expressed by Cramton and Stoft. In particular, he has testified that PJM pays resources for their capacity even in cases “of complete nonperformance” and that PJM’s “Wind, solar and hydro generation capacity resources are exempt from key performance incentives.”105 He further notes that PJM’s resource performance measurements are faulty because they “do not correctly measure actual forced outage performance because they exclude some forced outages.”106 Having a similar concern, PJM has requested that FERC allow it to change the rules governing its capacity market so that PJM can limit the amount of capacity outside the PJM territory that can 103 P. Cramton and S. Stoft, “A Capacity Market that Makes Sense,” Electricity Journal 18: 43-54, August/September 2005. 104 Cramton and Stoft acknowledge the difficulty of estimating the energy rents of an actual benchmark peaking unit in practical situations, such as when the unit has startup costs or a minimum start time that make a startup decision non-trivial. 105 Comments of the Independent Market Monitor for PJM, Centralized Capacity Markets in Regional Transmission Organizations and Independent System Operators, before the Federal Energy Regulatory Commission, Docket No. AD13-7-000, January 8, 2014, p. 5. 106 Id., p. 6. 67 bid into its capacity auctions.107 Oddly, PJM’s forward auctions recognize locational constraints that limit the delivery of capacity within PJM, but not the locational constraints that limit the delivery of capacity to PJM from areas outside of PJM. Indeed, PJM does not recognize capacity import limits in its capacity auctions. With the tripling of capacity imports over the past six years and occasional curtailment of firm transmission service by neighboring power systems, this failure to recognize deliverability constraints attaches too high a value to the reliability benefits of capacity imports. This is yet another instance in which the real value of capacity is less than its nominal value. ISO New England has recognized the fundamental principle of “pay for performance” in its recent proposal to FERC to amend its Forward Capacity Market (FCM) design. As ISO NE states: When sellers can depend on payment regardless of the quality of the product delivered, quality tends to suffer. When payments reward higher quality, quality tends to improve. While there have been many efforts to refine the FCM over the years, its design has always failed to reflect these most basic principles, and reliability in New England is deteriorating as a result. Much of the reason for the FCM’s failure in this regard is its complexity. The product is poorly defined; while the region requires resources that reliably provide energy and reserves when supply is scarce, the FCM instead buys something only vaguely related to that, called “availability.” The FCM applies different rules and different standards to different types of resources (even though it seeks to buy the same product from all of them), and includes numerous one-off provisions and exceptions. And at the end of the day, capacity “obligations” mean little because there are rarely financial consequences for failing to perform. Each of these elements of the current FCM is contrary to sound market design. This is not surprising, however, because the core FCM design was not based on any standard market model. Rather, the FCM was built from the ground up, without a blueprint, through a long series of negotiations and compromises. The result is an idiosyncratic design that is failing to meet its most basic objectives – ensuring reliability in a cost-effective manner. The solution to these problems is assuredly not more of the same. The FCM design must be fixed on a fundamental level. The Pay For Performance design presented here replaces the FCM’s esoteric design with one that is familiar. Pay For Performance is a true, two-settlement forward market, following a blueprint that has been tested, refined, and applied successfully in myriad other markets, including New England’s own energy markets. Pay For Performance is built around a well-defined product – the delivery of energy and reserves when they are needed most. Its rules are much 107 PJM Interconnection, L.L.C., Docket No. ER14-503-000, November 29, 2013. 68 more simple than the current FCM design, and those rules apply in the same manner to all resource types, without exceptions. With greater transparency and less uncertainty, Pay For Performance will create strong incentives for resource performance consistent with the goals of the capacity market.108 In summary, resources should be compensated for their capacity value only to the extent that they can support power system security when needed. Resource owners will have good incentives to perform only if they are paid for resources that are actually available when needed; and they should be penalized, or at the very least not paid, if their resources are not available when needed. This obvious reform should be undertaken expeditiously in all capacity markets that have a mismatch between rewards, penalties, and performance. 7.1.3. Recognition of the Diversity of Capacity Values FERC has recently asked the power industry how capacity markets might better recognize the diverse values provided by different types of capacity resources. FERC specifically asked: Should existing capacity products be modified to reflect various operational characteristics needed to meet system needs? If there is a need for additional capacity products, how should those products be defined and procured in light of the current one day in ten year resource adequacy approach?109 Some parties have asserted that the capacity values of all resources should be recognized. For example, a coalition of thirty publicly owned electric utilities, cooperatively owned electric utilities, consumer advocates, state public utility commissions, investor-owned utilities, industrial customers, and independent power producers has urged FERC to recognize the diversity of values provided by different types of resources, the legitimacy of policies that favor some resources over other resources, and the legitimacy of resources procured under longterm contracts and self-supply.110 Parties representing some particular types of resources have declared that special consideration should be given to the ways in which their resources provide capacity. For example, EnerNOC, which is in the business of developing demand-response resources, seeks different capacity market standards for demand-side resources than for supply-side resources. The basis for these different standards is that demand-side resources and supply-side resources perform differently than one another and have different business models. 108 ISO New England, ISO New England Inc. and New England Power Pool, Filings of Performance Incentives Market Rule Changes, Docket No. ER14-1050-000, January 14, 2014, p. 2. 109 Federal Energy Regulatory Commission, Notice Allowing Post-Technical Conference Comments, Centralized Capacity Markets in Regional Transmission Organizations and Independent System Operators, Docket No. AD13-7000, October 25, 2013, p. 3. 110 AARP et al, Letter to the Federal Energy Regulatory Commission, Centralized Capacity Markets in Regional Transmission Organizations and Independent System Operators, Docket No. AD13-7-000, February 10, 2014. 69 Demand response resources… are not in the business of selling load reductions as a primary business… [M]ust-offer mechanisms may be a good fit for generation but are a poor fit for demand response. Generation will choose to be dispatched as often as it is profitable to provide energy, while demand response generally would prefer not to be interrupted.111 As another example, the Energy Storage Association seeks capacity market rules that enable storage to better participate in capacity markets: Integrating storage resources into the existing capacity markets by the development of rules specific to these resources, as has been done for other alternative resources such as demand response, will send the right market signals for investment.112 Ensuring market rules are developed to enable storage resources to access to the capacity markets would remove a major barrier to investment in new storage resources.113 …in any given hour, a storage resource can be withdrawing or injecting power and yet the capacity markets currently do not allow for this type of resource.114 …energy storage facilities should be included in the planning process.115 The Maryland Public Service Commission advocates having separate capacity markets for existing resources and new resources: …RTO/ISOs could conduct bidding targeted at existing resources in the near to mid-term, while conducting a separate round of bidding designed and targeted at new resources that would be brought online in the mid to longer term; capacity that could come from upgrades at existing facilities or new generating resources. Surely, in almost every instance the payment necessary to persuade an existing efficient resource to commit to remaining available for a certain 111 Comments of EnerNOC Inc. On behalf of Dan Curran, Principal, Market Strategy, Centralized Capacity Markets in Regional Transmission Organizations and Independent System Operators, before the Federal Energy Regulatory Commission, Docket No. AD13-7-000, September 10, 2013, p. 3. 112 Statement of the Electricity Storage Assocation [sic], Centralized Capacity Markets in Regional Transmission Organizations and Independent System Operators, before the Federal Energy Regulatory Commission, Docket No. AD13-7-000, September 10, 2013, p. 3. 113 Id., p. 5. 114 Post-Technical Conference Comments Of The Energy Storage Assocation [sic], Centralized Capacity Markets in Regional Transmission Organizations and Independent System Operators, before the Federal Energy Regulatory Commission, Docket No. AD13-7-000, January 8, 2014, p. 5. 115 Id., p. 6. 70 period into the future will be much less than that necessary to incent construction of a new power plant.116 The Maryland Public Service Commission also advocates capacity products of different durations: FERC should also look at the desirability of requiring capacity markets to establish capacity payment terms of greater than one year, perhaps using a portfolio of staggered contract terms such as three, five, or ten years for a defined percentage of capacity resources – this approach would minimize price volatility and provide long term price signals which would also provide greater revenue certainty to developers of new merchant generation.117 The Maryland Public Service Commission also advocates compensating capacity for its different operational characteristics: Capacity compensation should vary to reflect the type and value of the capacity services provided to the market. This includes providing quick start, shutdown and load-following capability…118 On the other side, the American Public Power Association opposes the development of multiple capacity products: Trying to adapt these [capacity] markets to accommodate specific resource types and attributes, while an admirable goal, would make them only more complex and difficult to administer, potentially leading to further unintended negative results and yet more band-aid market rule changes and exceptions to attempt to address these unintended results.119 Joseph Bowring and David Patton, the Independent Market Monitors for PJM and New York ISO, respectively, each say that the special operational attributes of certain resources, like quick response, are best rewarded by the energy and ancillary services markets rather than by capacity markets: …it does not make sense to subdivide the capacity market by operational characteristics or other attributes. Such character[ist]ics are best dealt with in the energy markets and the ancillary services markets. Subdividing the capacity market into multiple submarkets would add exponential complexity to an 116 Comments of the Maryland Public Service Commission, Centralized Capacity Markets in Regional Transmission Organizations and Independent System Operators, before the Federal Energy Regulatory Commission, Docket No. AD13-7-000, September 9, 2013, p. 6. 117 Id. 118 Id., p. 7. 119 Written Statement Of Susan N. Kelly On Behalf Of The American Public Power Association, Centralized Capacity Markets in Regional Transmission Organizations and Independent System Operators, before the Federal Energy Regulatory Commission, Docket No. AD13-7-000, September 9, 2013, p. 16. 71 already complex market and would be likely to exacerbate existing market power issues as there are more dominant positions in the smaller submarkets.120 Capacity markets provide a powerful economic mechanism to facilitate investment in resources with certain operating characteristics. However, the capacity market should only be used to create such signals when the energy and ancillary services markets do not already provide efficient economic signals supporting the operating characteristic in question. For characteristics that are beneficial in operating the system, well-designed energy and ancillary services markets should fully and efficiently compensate the supplier for the operating characteristic… Additionally, making payments through the capacity market does not guarantee the characteristic will be available during the operations.121 Patton says that differences in resources operational characteristics should be recognized through adjustments in the capacity values attributed to different resources rather than through creation of multiple capacity products: …different types of resources or quality of resources contribute differently to satisfying the RTOs’ planning reserve requirements. For example, a unit with a 20 percent forced outage rate is not equivalent to a unit with a 5 percent forced outage rate. Similarly, intermittent resources with an average load factor of 30 percent are not equivalent to conventional generating resources. Hence, the RTOs generally employ a system to account for these differences. For example, PJM and NYISO calculate translate each unit’s installed capacity level into an “unforced capacity” or “UCAP” level that accounts for forced outages and intermittency. While there is room for improvement in how this UCAP translation is implemented, we believe it is far superior to normalize different types of resources into one common product rather than introducing multiple capacity products and corresponding requirements.122 While capacity markets do need to be differentiated by location because of deliverability constraints, there is no need to have separate markets for different types of capacity resources. All resources that can enhance power system reliability can and should be accepted as capacity resources. The differentiation among these resources should not be based upon their technologies or their ages, but should be based solely upon their performance: a higher price can be paid to a more valuable resource while a lower price is paid to a less valuable resource; or, equivalently, a higher capacity value can be assigned to a more available and responsive 120 Comments of the Independent Market Monitor for PJM, Centralized Capacity Markets in Regional Transmission Organizations and Independent System Operators, before the Federal Energy Regulatory Commission, Docket No. AD13-7-000, January 8, 2014, p. 8. 121 Post-Technical Conference Comments of Potomac Economics Ltd. New York ISO Market Monitoring Unit, Centralized Capacity Markets in Regional Transmission Organizations and Independent System Operators, before the Federal Energy Regulatory Commission, Docket No. AD13-7-000, January 8, 2014, p. 6. 122 Id., p. 5. 72 resource while a lower capacity value is assigned to a less available and responsive resource. Resources that can enhance reliability should not be kept out of capacity markets by virtue of their operational limitations; but if those limitations reduce their reliability value relative to other resources, they should be paid a lower price or be assigned a lower capacity value that reflects the reduced reliability value. For the purpose of providing efficient incentives for resource investment and resource retirement, we offer the following comments relevant to the foregoing proposals:  If demand-side resources are less available than supply-side resources, they have less reliability value and should be compensated accordingly.  The value of the quick response of storage resources should be fully compensated in ancillary services markets, not in capacity markets.  Energy-limited resources, including some demand-side and storage resources, may have less reliability value than resources without this limitation, and should be compensated accordingly.  Existing and new resources should be compensated differently only to the extent that their operational characteristics give them different reliability values.  Resources procured through different institutional arrangements – through investment, bilateral contracts, or centralized markets – should be compensated differently only to the extent that the operational characteristics of the underlying resources give them different reliability values. One of the important lessons learned from the polar vortex experience is the value of fuel diversity, which determines the diversity in the fuel mix of capacity available to maintain grid reliability under extreme weather conditions. Donald Schneider, President of FirstEnergy Solutions, speaking at the FERC technical conference on polar vortex issues, stated: You can't have the backbone of the electric system that is counted on for reliability operated on an essentially just-in-time interruptible fuel supply. There is a need to maintain diversity in a fuel supply, and it is particularly important to value on-site fuel optionality… The recent influx of new gas and renewable generation resources has created a challenge for our industry. These new resources do not have the same operational and reliability benefits as essential generation. As market and social forces change the diversity of our fuel mix, it is our responsibility to maintain an even stronger focus on preserving reliability, and this can't be done through planned transmission upgrades alone… The nearterm goals should include a mechanism that adequately compensates resources for the value they provide. The longer term goal should be to enhance the 73 market construct to maintain on a self-sustaining basis fuel diversity, ensuring that markets maintain a strong focus on reliability.123 In keeping with Mr. Schneider’s remarks, John Sturm, Vice President of Corporate and Regulatory Affairs, for the Alliance for Cooperative Energy Services (ACES), urged FERC to avoid “additional regulations that might expedite or cause additional coal or nuclear [plant] retirements.”124 7.2. Reforms in Methods for Meeting Capacity Mandates 7.2.1. Resource Obligations Borne by Distribution Service Providers Cliff Hamal of Navigant Economics has proposed that capacity resource obligations be borne by distribution wires companies rather than by LSEs.125 The major motivation for this so-called “BiCap” (“bilateral capacity market”) approach is that the “ability for customers to switch suppliers has made it virtually impossible for LSEs to take on long-term obligations to purchase capacity.”126 Key elements of the BiCap approach include the following:  Capacity obligations would be the responsibility of distribution companies.  Existing RTO capacity markets would be eliminated. RTOs would no longer play any role in setting capacity prices, developing capacity demand curves, or dealing with market power.  RTOs would continue to determine capacity needs based upon NERC standards, peak loads, and deliverability constraints.  RTOs would assess penalties on distribution companies that fail to meet their obligations. Hamal claims that placing capacity obligations on distribution companies has the following advantages relative to placing these obligations on LSEs:  Because load in competitive markets can easily migrate among LSEs but can migrate only with great difficulty among distribution service providers, distribution companies 123 Federal Energy Regulatory Commission, In the matter of Technical Conference On Winter 2013-2014 Operations and Market Performance In RTOs and ISOs, Docket No. AD14-8-000, Transcript, pp. 210-213. 124 Id., pp. 229-230. 125 C. Hamal, Solving the Electricity Capacity Market Puzzle: The BiCap Approach, Navigant Economics, July 4, 2013. 126 Id., p. 3. 74 are in a better position to make long-term capacity procurement arrangements than are LSEs.127  Because of customers’ implicit long-term commitments to their local distribution companies, distribution companies can sign long-term contracts with generators that will allow them to reduce their financing costs by increasing their ability to borrow money long-term.  Distribution companies can tailor capacity resources to meet their particular local network problems.  Distribution companies are better able to compare transmission alternatives. The BiCap approach offers an intriguing solution to LSEs’ understandable reluctance to make long-term capacity commitments when they lack long-term purchase commitments from their customers. BiCap also has some weaknesses that arise from its division of capacity rights ownership and capacity needs: capacity rights would be owned by parties (the distribution companies) who are different than the parties who need to exercise those rights (the LSEs). Ideally, capacity would be purchased by parties who balance the costs of capacity with the values of the energy and ancillary services that the capacity can provide, with due consideration of the capacity resource’s operating costs and expected availability. Under BiCap, however, the impacts of capacity procurement decisions are bifurcated: distribution providers choose and bear the costs of the capacity, while LSEs bear the operating cost and availability consequences. Distribution providers would therefore have strong incentives to minimize their capacity costs; and they would have only weak incentives to maximize the net value of the services provided by a resource, including consideration of that resource’s performance and operating costs relative to market values. In other words, distribution providers might buy the cheapest capacity rather than the best capacity.128 The BiCap approach does address a key weakness of existing capacity markets, namely the absence of truly long-term commitments. Perhaps further development of this approach can address the incentive problems that arise from the division of capacity ownership and capacity needs. 127 Some commercial and industrial load can migrate among distribution companies by moving production from a site located in one distribution company’s service area to another site located in another distribution company’s service area. 128 Some of these concerns may also apply to present RTO capacity markets, wherein LSEs pay for capacity while RTOs exercise the capacity rights. As with the present RTO capacity markets, the problem of capacity quality could be addressed by appropriate capacity performance rules. 75 7.2.2. Capacity Options Several authors have suggested that the adequacy problem can be addressed through the forward procurement of reliability options, also referred to as capacity options.129 These instruments are similar to call options. Whenever the wholesale spot market price exceeds a pre-set reference price (the “strike price”), the contracted capacity supplier must pay the excess to the option owner (such as an LSE). In exchange for writing this option, the capacity supplier receives a fixed capacity payment. There are three advantages of this capacity option approach. First, the capacity supplier benefits from a stable and predictable income stream. Second, the capacity supplier has a strong incentive for its resource(s) to be available at times of scarcity: if the supplier’s resource is not available, the supplier will have to meet the payments under the capacity option contract without receiving any market revenue at a time of high market prices. Third, the buyers of capacity options effectively cap their electricity purchase price at the level of the strike price, since whenever the market price increases above this level, the excess will be “reimbursed” through the payment made by the capacity supplier under the option contract. This provides the buyer with a hedge against spot market price volatility risk. Capacity options can be designed in a number of ways, depending on whether the scheme is purely financial or also involves an obligation to have and make capacity available when the option is exercised (or otherwise face a penalty). The latter obligation provides assurance that reliability is supported. In such a case, the capacity option becomes similar to a scheme based on capacity obligations. In either case, the capacity option can be priced through a forward auction similar to what the RTOs have in place today. 7.2.3. Treatment of Self-Supply Relative to Centralized Capacity Markets Until the formation of RTOs, LSEs could meet their capacity obligations through direct investment, shared investment, and bilateral purchase contracts. In the hundred years of power industry history up to the creation of the RTOs, there were no centralized capacity markets. The creation of the RTOs’ centralized capacity markets has been accompanied, in some cases, by requirements that LSEs meet their capacity obligations solely through capacity resources that clear the centralized capacity market auctions. Several representatives of consumers and LSEs have objected that these requirements create potential obstacles to traditional “selfsupply” of resources – that is, direct investment in, shared investment in, and bilateral purchase of capacity resources. In cases wherein an LSE procures a self-supplied capacity resource that does not clear in the centralized capacity market auction, the LSE will not only pay for the self- 129 For example, see P. Cramton, A. Ockenfels, and S. Stoft, “Capacity Market Fundamentals”, Economics of Energy & Environmental Policy, Vol. 2, No. 2, 2013; and The Agency for the Cooperation of Energy Regulators, Capacity Remuneration Mechanisms and the Internal Market for Electricity, July 30, 2013. 76 supplied resource but will also be forced to pay a substantial penalty to the RTO. 130 The American Public Power Association has asked FERC to “restore the ability of public power systems in the three Eastern RTOs to self-supply their own loads with their own resources.”131 The National Rural Electric Cooperative Association has said that “the Commission need only satisfy itself that LSEs have a genuine ability to use the capacity resources that they build themselves or acquire in the bilateral market to satisfy their capacity obligations.”132 The Transmission Access Policy Study Group has said that “the Commission should preserve and maximize LSE self-supply and state procurement options.”133 The opposition to mandatory participation in the RTOs’ centralized capacity markets is partly concerned with the inconsistency between the short-term nature of those markets in contrast to the long-term nature of capacity itself. As stated by the Maryland Public Service Commission: FERC must preserve the ability of sophisticated buyers and sellers to engage in mutually beneficial long-term transactions. At present, capacity market mechanisms do not provide the signals, nor the opportunity, for developers of new generation to obtain the market assurance they need to commit capital based on a reasonably certain revenue stream required to obtain competitive financing and ensure long-term revenue adequacy. This is precisely where ensuring that willing buyers and sellers can enter into mutually beneficial longterm contracts for capacity and energy will help to remove one impediment to new capacity…134 130 FERC has recently approved a more lenient self-supply option for PJM, although it has not yet done so in New England or New York. See Federal Energy Regulatory Commission, 143 FERC ¶61,090 (2013), PJM Interconnection LLC, Order Conditionally Accepting in Part, and Rejecting In Part Proposed Tariff Provisions, Subject to Conditions, May 2, 2013. 131 Written Statement Of Susan N. Kelly On Behalf Of The American Public Power Association, Centralized Capacity Markets in Regional Transmission Organizations and Independent System Operators, before the Federal Energy Regulatory Commission, Docket No. AD13-7-000, September 9, 2013, p. 8. APPA has also offered a broader and more detailed reform proposal, in addition to its first priority of restoring LSEs’ self-supply rights. See Section IV (page 61+) of its post-technical conference comments at http://www.publicpower.org/files/PDFs/APPA_PostTechnical_Conference_Comments_AD13-7_Final_1392150690180_2.pdf. 132 Post-Technical Conference Comments of the National Rural Electric Cooperative Association, Centralized Capacity Markets in Regional Transmission Organizations and Independent System Operators, before the Federal Energy Regulatory Commission, Docket No. AD13-7-000, January 8, 2014, p. 4. 133 Post-Technical Conference Comments of the Transmission Access Policy Study Group, Centralized Capacity Markets in Regional Transmission Organizations and Independent System Operators, before the Federal Energy Regulatory Commission, Docket No. AD13-7-000, January 8, 2014, p. 3. 134 Comments of the Maryland Public Service Commission, Centralized Capacity Markets in Regional Transmission Organizations and Independent System Operators, before the Federal Energy Regulatory Commission, Docket No. AD13-7-000, September 9, 2013, p. 8. 77 Similarly, the Transmission Access Policy Study Group says: …the spot capacity market should be residual to LSE self-supply, state procurement, and the longer-term bilateral market. Only markets that provide the potential for long-term commitments to support long-lived, capital-intensive investments are capable of maintaining resource adequacy and meeting other federal, state, and local energy policies. Residual capacity markets are also fully consistent with the Commission‘s original vision.135 Referring to the PJM’s capacity market, the PJM Industrial Customer Coalition asserts that: RPM should be recognized as a residual procurement. In fact, the descriptor applied to the principal set of annual RPM auctions ― the Base Residual Auction ― reflects that it was intended to be the process by which capacity would be procured to meet the needs of load after taking account of self-supply.136 The APPA also urged the FERC to reform RTO capacity markets by making them “voluntary residual procurement mechanisms… “intended to supplement other, primary methods of procuring capacity (e.g., bilateral contracting or self-builds), and to lay off or procure marginal supply.”137 Joseph Bowring, head of Monitoring Analytics, PJM’s Independent Market Monitor, explains that the value of the centralized capacity markets is that they provide price transparency and thereby encourage efficient provision of capacity: A single central capacity market is clearly preferable to a series of bilateral contracts… The capacity market is transparent and market outcomes reflect supply and demand fundamentals. A bilateral market is opaque to market participants and provides opportunities to exercise market power in the presence of very little information about market fundamentals and likely significant asymmetries in access to information.138 Bowring explains that the RTOs’ centralized capacity markets cannot serve as residual markets, particularly if LSEs finance their self-supply through traditional cost-of-service regulation: 135 Post-Technical Conference Comments of the Transmission Access Policy Study Group, Centralized Capacity Markets in Regional Transmission Organizations and Independent System Operators, before the Federal Energy Regulatory Commission, Docket No. AD13-7-000, January 8, 2014, p. 15. 136 Post-Technical Conference Comments of the PJM Industrial Customer Coalition, Centralized Capacity Markets in Regional Transmission Organizations and Independent System Operators, before the Federal Energy Regulatory Commission, Docket No. AD13-7-000, January 8, 2014, p. 14. 137 Written Statement Of Susan N. Kelly On Behalf Of The American Public Power Association, Centralized Capacity Markets in Regional Transmission Organizations and Independent System Operators, before the Federal Energy Regulatory Commission, Docket No. AD13-7-000, September 9, 2013, pp. 63-64. 138 Comments of the Independent Market Monitor for PJM, Centralized Capacity Markets in Regional Transmission Organizations and Independent System Operators, before the Federal Energy Regulatory Commission, Docket No. AD13-7-000, January 8, 2014, p. 12. 78 A residual market by definition relies on other mechanisms to acquire capacity. If the other mechanism is cost of service regulation, then the residual market will not result in a price that reflects the fundamentals of supply and demand conditions. Such a residual market is very unlikely to result in incentives adequate for a merchant generator to profitably build new generation.139 He therefore finds that the RTOs’ centralized capacity markets cannot properly function if participation in those markets is not mandatory: The most important point about all the approaches to the net revenue problem is that they are mutually exclusive. If a market chooses the cost of service paradigm based on state regulated cost of service revenue guarantees, it makes it impossible to have a competitive capacity market. It is not possible for a competitive merchant generation developer to compete with such revenue guarantees.140 Again, all resources that can enhance power system reliability can and should be accepted as capacity resources; and the value of those resources should be based solely upon their performance, not on the means by which they are acquired. The RTOs’ centralized capacity markets are problematic because they are so short-term: by design, they cannot be expected to support long-term investment. Making participation in the centralized markets mandatory has the perverse effect of creating incentives that undermine long-term investment and that, in particular, undermine a capacity investment model that has worked well, if imperfectly, for over a century. Mandatory participation also limits LSEs’ ability to fashion solutions that fit their own individual situations, or increases LSE’s costs of doing so. 7.2.4. Reform of LMP Pricing Because resource investments depend upon energy and ancillary services prices, those prices need to be efficient. Unfortunately, energy and ancillary services prices are inefficiently reduced by public policies that support particular types of resources (e.g., renewable resources) and by RTO actions to support power system security through out-of-market purchases of energy and ancillary services. The Electric Power Supply Association explains the latter problem as follows: …LMPs are understating the revenue required to reliably meet demand for electricity in wholesale markets. This occurs when grid operators frequently take actions without transparency and accountability to call on resources outside of economic merit order that are compensated other than through LMPs. Instead, these other resources are paid through what is called uplift, a cost that is spread among load outside of the LMP mechanism. By definition, the resulting LMPs when this occurs understate the amount of revenue necessary to serve the 139 Id., p. 12. 140 Id., p. 13. 79 system because the LMPs do not include the cost of taking all of the actions actually taken in the name of reliability but paid via uplift instead. This significantly mutes the price signals including forward prices on which investment decisions are based resulting in muted investment relative to what is required in a competitive market.141 The reductions in energy prices can result in significant revenue loss for generators and reduced incentives for needed investment. As the Electric Power Supply Association states, the determination of LMPs should be reformed so that all resources receive higher energy prices when the RTOs find it necessary to make out-of-market payments to support reliability. 8. CONCLUSIONS The U.S. electric power industry has a one-hundred-year history of providing capacity resources that have been adequate under all but the most extreme conditions. The main contributor to this favorable outcome has been a set of power industry business practices that require resources to exceed peak loads according to certain engineering-based analyses or rules of thumb. These industry practices have been supplemented and strengthened by various state proceedings such as integrated resource planning. While traditionally regulated electricity markets have issues such as contentious prudence determinations, these markets continue to meet resource adequacy requirements under the supervision of state regulators. The current debate on resource adequacy arises primarily from questions about how to make the restructured markets’ model work. These questions arise from the following fundamental causes:  RTOs’ short-term centralized capacity markets do not provide incentives for long-term resource investments. These markets were designed to improve the short-term commitment and dispatch of power system resources; and for this short-term purpose, they have been very successful.142 But these RTO markets, being short-term markets, do not and cannot address long-term capacity needs. In the words of one of the prominent advocates of these markets, “Many in the industry confuse RTOs’ mandatory forward procurement with longer-term forward contracting. They are not substitutes; 141 Comments of the Electric Power Supply Association, Centralized Capacity Markets in Regional Transmission Organizations and Independent System Operators, before the Federal Energy Regulatory Commission, Docket No. AD13-7-000, January 8, 2014, p. 12. 142 The engineering-economics basis for electricity restructuring in general and for LMP calculations in particular is entirely short-term. For one of the original articles describing this basis, see R.E. Bohn, M.C. Caramanis, and F.C. Schweppe, "Optimal Pricing in Electrical Networks Over Space and Time", Rand Journal of Economics, 15(3): 36076, Autumn 1984. A more comprehensive description can be found in F.C. Schweppe, M.C. Caramanis, R.D. Tabors, and R.E. Bohn, Spot Pricing of Electricity, Kluwer Academic Publishers, Boston, 1987. The mathematics of the RTOs’ present energy and ancillary service price determinations are elaborations of the ideas presented in these publications. 80 Bilateral forward contracting remains key under any market design for locking in revenues and facilitating financing of new resources.”143 Contrary to this key necessity, however, the RTO markets include some design elements that impede long-term investments and long-term bilateral contracts.  The political process will not allow peak-period demand pricing or rationing that is consistent with a market solution. Specifically, the RTOs’ energy and ancillary services prices are capped by politically risk averse regulators; and on the rare occasions when non-price rationing (e.g., rolling blackouts) occurs due to capacity shortfall, that rationing does not tend to discriminate between those consumers and retail suppliers who arrange adequate supplies and those who do not.  Electricity customers are generally not willing to pay explicit prices consistent with the high cost of building the resources that are required to avoid peak-period demand rationing. In particular, the one-event-in-ten-year rule of thumb has an incremental cost that is far above many customers’ willingness to pay for reliability. Outage costs do vary widely among customers. Nonetheless, because customers’ willingness to pay for reliability is generally well below that needed to support the power industry’s usual planning reserve requirements, markets alone will not support the capacity requirements implied by the power industry’s reliability practices, even with a perfectly functioning demand-side of electricity markets. These fundamental causes imply that the resource adequacy problem does not have a market solution. The RTOs, as they struggle to fit a square peg into a round hole, must therefore continually reform their capacity markets, sometimes in major ways, always through contentious proceedings, as they search for a market solution that cannot exist under existing political and regulatory frameworks. While a well-functioning market attracts participation because that market provides trades on terms that are comparable to or better than those available through other venues, the RTOs’ centralized capacity markets tend to be mandatory because, as many parties have indicated, there are venues in which capacity services are available on better terms than are available in the RTOs’ centralized capacity markets. There are few places in the American economy wherein one can find a free market in which participation is mandatory. The traditionally regulated markets avoid all the foregoing problems by simply not attempting a market solution, except to the extent that they have competitive bidding procedures to meet identified capacity needs. The RTOs could do the same thing: set capacity requirements according to engineering criteria; impose high penalties on those LSEs who fail to meet their requirements; and offer a centralized market for those parties who find that market’s terms attractive. 143 D.B. Patton, Resource Adequacy in Wholesale Electricity Markets: Principles and Lessons Learned, Federal Energy Regulatory Commission Technical Conference on Centralized Capacity Markets in Regional Transmission Organizations and Independent System Operators, Docket No. AD13-7-000 September 25, 2013, p. 8. 81 There are additional matters that should be, and indeed already are, of great concern to policymakers and all stakeholders in the electric power industry:  The reliability of some portions of the power system has been challenged by a lack of fuel diversity in new generation development. The cold winter of 2013-2014 (the “polar vortex”) and the accompanying gas price spikes and gas delivery issues highlight the perils of over-reliance on any one fuel.  Gas-electric coordination has become increasingly important as we rely more on natural gas. Questions arise as to whether generation can be counted as firm capacity if it does not have firm transportation contracts. Again, the polar vortex was a demonstration of the possible implications of insufficient firm transportation.  The planned retirement of coal plants (for both economic and environmental reasons), the retirement of two nuclear plants for economic reasons, and the possible retirement of more nuclear plants will exacerbate the resource adequacy problem in most RTOs, creating significant reliability concerns.  There is reasonable concern about the capacity value of demand-side resources. It is risky to over-rely on these resources until they have been thoroughly tested by experience.  There is reasonable concern about the capacity value of intermittent resources, and about the power system control and security problems raised by their intermittency. There have been many proposals made to reform capacity markets or to design new methods to ensure resource adequacy in the restructured markets, but most of these proposals assume that tweaks to the restructured market model will be sufficient. A more comprehensive solution is necessary, however. For example, the restructured markets could be designed to that capacity is procured in ways similar to those used in traditional regulated markets: set capacity requirements according to engineering criteria; impose high penalties on those LSEs who fail to meet their requirements; and offer a centralized market for those parties who find the centralized market’s terms attractive. Generation could be procured through competitive solicitation as it is done successfully in some traditionally regulated markets as well as in some restructured markets. And RTOs could continue to operate energy markets in the same way as they do today. Our nation needs to continually strive for better regulatory and market rules that ensure resource adequacy at reasonable cost to consumers and the economy. We recommend that regulators and legislators, at both the federal and state levels, closely examine the resource adequacy problem in restructured markets and develop solutions soon. Because of the significant time that is required to develop new resources, we cannot afford to wait until resource adequacy problems become more acute. 82 From: To: Subject: Date: Beth L. Soliere Bob Stump RE: New Orleans HEPG Monday, December 01, 2014 10:51:48 AM Yes. We have both been asking for weeks, but this is good news. I will ask that they give you two beds.   From: Bob Stump Sent: Monday, December 01, 2014 10:38 AM To: Beth L. Soliere Subject: Fwd: New Orleans HEPG   Assume this was meant for me...Theresa asked here  Sent from my iPhone Begin forwarded message: From: "Mahoney, Jo-Ann" Date: December 1, 2014 at 10:32:26 AM MST To: "Beth L. Soliere" , Bob Stump Subject: New Orleans HEPG Good morning Beth,   We were able to secure a reservation for Chairman Stump for both nights (Wednesday, December 3 and Thursday, December 4) at the Windsor Court Hotel, where the conference will take place.   The hotel is located at 300 Gravier Street, New Orleans.   The commissioner’s reservation number is:  65999225-1.   Best, Jo-Ann     Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu         From: Teresa Tenbrink [mailto:ttenbrink@azcc.gov] Sent: Monday, December 01, 2014 11:35 AM To: Mahoney, Jo-Ann; Bruner, Hannah Subject: New Orleans HEPG   Good morning,   Commissioner Bitter Smith was inquiring about which hotel her reservation will be at while she’s in New Orleans.  Can you provide the name of the hotel and the confirmation number?   Many thanks,   Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   From: To: Subject: Date: Mahoney, Jo-Ann Beth L. Soliere; Bob Stump New Orleans HEPG Monday, December 01, 2014 10:33:11 AM Good morning Beth,   We were able to secure a reservation for Chairman Stump for both nights (Wednesday, December 3 and Thursday, December 4) at the Windsor Court Hotel, where the conference will take place.   The hotel is located at 300 Gravier Street, New Orleans.   The commissioner’s reservation number is:  65999225-1.   Best, Jo-Ann     Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu         From: Teresa Tenbrink [mailto:ttenbrink@azcc.gov] Sent: Monday, December 01, 2014 11:35 AM To: Mahoney, Jo-Ann; Bruner, Hannah Subject: New Orleans HEPG   Good morning,   Commissioner Bitter Smith was inquiring about which hotel her reservation will be at while she’s in New Orleans.  Can you provide the name of the hotel and the confirmation number?   Many thanks,   Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   From: To: Subject: Date: Bob Stump Beth L. Soliere Re: Sheraton at HEPG Friday, November 21, 2014 2:28:30 PM Thanks. Also RSVP for dinner invite would be good.  Dr. Jane Stump and I.   On Fri, Nov 21, 2014 at 12:32 PM, Beth L. Soliere wrote: I will request that.   From: Bob Stump [mailto:repbobstump@gmail.com] Sent: Friday, November 21, 2014 12:31 PM To: Beth L. Soliere Subject: Sheraton at HEPG   Since my mother will be coming, if they could offer two beds, would be great.  Shouldn't be an extra charge. -Bob Stump Chair, Phoenix Opera 3120 West Carefree Highway, Suite 1-106 Phoenix, AZ 85086   Chair, Arizona Corporation Commission 1200 W. Washington Phoenix, AZ  85007 602-542-3935 -Bob Stump Chair, Phoenix Opera 3120 West Carefree Highway, Suite 1-106 Phoenix, AZ 85086 Chair, Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 602?542?3935 From: To: Cc: Subject: Date: Attachments: Mahoney, Jo-Ann Mahoney, Jo-Ann Bruner, Hannah HEPG New Orleans Meeting Wednesday, November 19, 2014 1:20:10 PM HEPG_12_14_DraftAgenda.docx We look forward to your participation in the Harvard Electricity Policy Group meeting to be held at the Windsor Court Hotel in New Orleans on Thursday-Friday, December 4-5, 2014.  Our draft agenda is attached.   On Thursday evening, December 4, we will hold the conference reception and dinner at Chef Donald Link’s Calcasieu, in the historic warehouse district.  Transportation will be provided. You are welcome to bring a guest who is travelling with you. Kindly RSVP to Hannah Bruner by November 25 (e-mail or 617-496-6760).   I look forward to seeing you in NOLA.    My best for the Thanksgiving holiday, Jo-Ann   Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu     HARVARD ELECTRICITY POLICY GROUP HARVARD ELECTRICITY POLICY GROUP SEVENTY-SEVENTH PLENARY SESSION Windsor Court Hotel New Orleans, LA THURSDAY AND FRIDAY, DECEMBER 4 - 5, 2014 DRAFT AGENDA Thursday, December 4 8:30 am Breakfast and Informal Discussion 9:00 am Session One. Environmental Dispatch: Now? Or Never? The notion of using environmental criteria to dispatch power plants has periodically arisen as an approach to reduce emissions. The theory seems simple to some, namely that plants are to be dispatched on an emissions merit order basis, least emitting sources first, subject of course to security constraints. While the idea may be simple, actual implementation would raise many questions. What would environmental protocols look like? How does one balance between economic and environmental merit orders? How do incremental costs for out of economic merit order get allocated? How might such a system fit into Section 111(d) SIP’s? What impact would environmental dispatch have on LMPs and FTR markets? Would the standard market design collapse or adapt? Are all plants capable of operating in a fashion that would allow for emissions based dispatch, and if not, how should that be dealt with? How do multi-state system operators dispatch in an environmental merit order when various states may have different, if not conflicting, compliance programs? How would emissions trading be altered by environmental dispatch? In short, how would such a system work and can it be done on a reasonable efficient basis? George Angelidis, California Independent System Operator Adam Keech, PJM Interconnection Jonathan Schrag, New York University School of Law *EDF representative *Invited. HEPG Agenda, December 4-5, 2014 Thursday, December 4 (cont’d) 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Lunch 1:15 pm Session Two. Technology and Resource Choice: What Value Diversity? Natural gas has clearly become the “fuel of choice” for new generation in the United States. That “choice,” of course, was not dictated by policy but rather by the marketplace. The competitors of gas -- primarily coal, nuclear, and renewables -- have been either more expensive, less reliable, or environmentally riskier, or perceived to have some combination of those market disadvantages. The result has been what some have characterized as a market driven “rush to gas.” Some would contend that resource decisions need to better take into account the benefits of diversity in resources. Prior to the emergence of competition, vertically integrated utilities, as well as regulators, through integrated planning processes could try to optimize such long and short term considerations. Is such an effort possible in a competitive market? Is it needed, or, over time will market forces balance things out? Renewables in many jurisdictions have their own set aside market: renewable portfolio standards. Nuclear and coal have no such set aside haven from the market. Should RTO planning processes be required to explicitly address portfolio diversity? If so, what criteria should be used in forgoing currently knowable price information in favor of longer-term insulation from volatility? What reasonable risks should a merchant generator be expected to take when it opts for a resource that is out of the market at present? How would the costs of any above current market plants be allocated? Are the prices for “out of market” resources actually brought back into the market by virtue of having fuel on site, or other reliability/systems operations perspectives? What would such a planning process do to the competitive nature of the marketplace? Bill Allen, American Electric Power Joseph Dominguez, Exelon Corporation Larry Makovich, IHS Richard O'Neill, Federal Energy Regulatory Commission 2:45 pm Coffee Break 3:00 pm Discussion 4:15 pm Adjourn 6:30 pm Reception and Dinner HEPG Agenda, December 4-5, 2014 Friday, December 5 8:30 am Breakfast and Informal Discussion 9:00 am Session Three. Resource Adequacy Reconsidered: Mandates and Markets Assuring resource adequacy has been an ongoing challenge since the transition to competition began. A number of measures have been taken to try to address the matter. These include the development of capacity markets and demand response programs. Events and continuing reform initiatives challenge both the effectiveness and costs of these programs. Criticisms of capacity markets continue. And the court decisions on Order 745 raise new questions about how to address demand response. An addition to resource adequacy concerns is fuel supply and pipeline capacity. While this issue has been of particular concern in New England, where pipeline capacity is highly constrained at certain times of the year, it has the potential, given the country’s increased reliance on natural gas, to become a problem elsewhere as well. How far can we rely on markets to assure resource adequacy? What mandates are required? Does the mandate of capacity markets mix with the market model of generation supply? What alternatives are available to supply and demand options organized in mandatory capacity markets? Do mandates support or replace market solutions? Bruce Edelston, Energy Policy Group Susan Kelly, American Public Power Association Don Santa, INGAA John Shelk, Electric Power Supply Association 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Adjourn From: To: Subject: Date: Bob Stump Beth L. Soliere Re: HEPG New Orleans: Deadline October 31, panel descriptions Monday, November 17, 2014 9:34:15 AM My mom got rooms. So kindly let them know not to worry about it. And thanks them  On Monday, November 17, 2014, Beth L. Soliere wrote: FYI   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Friday, November 14, 2014 4:24 PM To: Beth L. Soliere Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions   Beth,   Rooms in New Orleans are very hard to come by during this period.  We are working on it.   Best, Jo-Ann From: Beth L. Soliere [BLSoliere@azcc.gov] Sent: Friday, November 14, 2014 4:31 PM To: Mahoney, Jo-Ann Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions Hi Jo-Ann,   Just checking back. I didn’t hear back from Hannah.   Thanks,   Beth   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Monday, November 10, 2014 2:34 PM To: Beth L. Soliere Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions   Beth,  I will ask Hannah to do so when she returns to the office tomorrow.  Jo-Ann  How many days? From: Beth L. Soliere [BLSoliere@azcc.gov] Sent: Monday, November 10, 2014 4:30 PM To: Mahoney, Jo-Ann Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions Okay, no problem.  Could you get him a few extra days that he will pay for but would be for the same rate?   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Monday, November 10, 2014 2:18 PM To: Beth L. Soliere Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions   Yes.  They are on a wait list at the Windsor Court.   From: Beth L. Soliere [BLSoliere@azcc.gov] Sent: Monday, November 10, 2014 3:50 PM To: Mahoney, Jo-Ann Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions Okay, for both Bitter Smith and Stump?   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Monday, November 10, 2014 12:56 PM To: Beth L. Soliere Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions   Beth,   We have put the commissioners in a nearby hotel, the Sheraton, as this hotel has completely sold out.  I apologize for that.   Best, Jo-Ann From: Beth L. Soliere [BLSoliere@azcc.gov] Sent: Monday, November 10, 2014 12:57 PM To: Mahoney, Jo-Ann Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions Hi Jo-Ann,   Would it be possible for the hotel to extend the group rate to Chairman Stump for a few extra days following the meeting?   Thank you!   Beth   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Monday, November 03, 2014 12:43 PM To: Beth L. Soliere Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions   We have done so, Beth, and will send you a confirmation later in the week.   From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Monday, November 03, 2014 2:39 PM To: Mahoney, Jo-Ann Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions   Hi Jo-Ann,   I am wondering if you or Hannah can set Chairman Stump up with a hotel room at the Windsor Court?   Thank you,   Beth   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Tuesday, October 28, 2014 11:01 AM To: Mahoney, Jo-Ann Cc: Bruner, Hannah Subject: HEPG New Orleans: Deadline October 31, panel descriptions   Dear Commissioner,   We invite you to attend the next meeting of the Harvard Electricity Policy Group, scheduled to take place at the Windsor Court Hotel in New Orleans, Louisiana on Thursday-Friday, December 4-5-2014.  We will dedicate one discussion session to “Technology and Resource Choice:  What Value Diversity?, and one session to “Environmental Dispatch:  Now? Or Never?”  (Descriptions below.)  The third panel will be announced shortly.  For your planning purposes the meeting will convene on Thursday morning at breakfast (8:30 am) and adjourn at noon on Friday.  The conference reception and dinner will take place on Thursday evening.   We are able to cover travel expenses, within reason, and can arrange a room at the Windsor Court Hotel for Wednesday, December 3 and Thursday, December 4.    Kindly let us know by Friday, October 31, if you would like to attend.  We apologize for the short notice, as we were waiting to vet our conference topics.  I would like to take this opportunity to introduce you to Hannah Bruner, our new project assistant, who will be working with the commissioners on logistics.  She can be reached at 617-496-6760 (Hannah.Bruner@hks.harvard.edu).   We hope that you can join us in New Orleans.  Kindly return the conference registration form and request for a hotel room to Hannah Bruner’s attention.   Best, Jo-Ann   Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu   Technology and Resource Choice: What Value Diversity?   Natural gas has clearly become the “fuel of choice” for new generation in the United States,  That “choice,” of course was not dictated by policy, but, rather by the marketplace.  The competitors of gas, primarily coal, nuclear, and renewables, have been either more expensive, less reliable, or environmentally riskier, or perceived to have some combination of those market disadvantages.  The result has been what some have characterized as a market driven “rush to gas.” Some would contend that resource decisions need to better take into account the benefits of diversity in resources.  Prior to the emergence of competition, vertically integrated utilities, as well as regulators, through integrated planning processes could try to optimize such long and short time considerations. Is such an effort possible in a competitive market? Is it needed, or, over time will market forces balance things out? Renewables in many jurisdictions have their own set aside market, renewable portfolio standards.  Nuclear and coal, have no such set aside haven from the market. Should RTO planning processes be required to explicitly address portfolio diversity?  If so, what criteria should be used in forgoing currently knowable price information in favor of longer term insulation from volatility? What reasonable risks should a merchant generator be expected to take when it opts for a resource that is out of the market at present?  How would the costs of any above current market plants be allocated?  Are the prices for “out of market” resources actually brought back into the market by virtue of having fuel on site, or other reliability/systems operations perspectives? What would such a planning process do to the competitive nature of the marketplace?   Environmental Dispatch: Now? Or Never?   The notion of using environmental criteria to dispatch power plants has periodically arisen as an approach to reduce emissions.  The theory seems simple to some, namely that plants are to be dispatched on an emissions merit order basis, least emitting sources first, subject, of course to security constraints.  While the idea may be simple, actual implementation would raise many questions. What would environmental protocols look like?  How does one balance between economic and environmental merit orders?   How do incremental costs for out of economic merit order get allocated? How might such a system fit into Section 111(d) SIP’s? What impact would environmental dispatch have on LMPs and FTR markets? Would the standard market design collapse or adapt? Are all plants capable of operating in a fashion that would allow for emissions based dispatch, and if not, how should that be dealt with?  How do multi-state system operators dispatch in an environmental merit order when  various states may have different, if not conflicting, compliance programs?  How would emissions trading be altered by environmental dispatch? In short, how would such a system work and can it be done on a reasonable efficient basis? -Bob Stump Chair, Phoenix Opera 3120 West Carefree Highway, Suite 1-106 Phoenix, AZ 85086   Chair, Arizona Corporation Commission 1200 W. Washington Phoenix, AZ  85007 602-542-3935 From: To: Subject: Date: Mahoney, Jo-Ann Beth L. Soliere RE: HEPG New Orleans: Deadline October 31, panel descriptions Friday, November 14, 2014 4:23:57 PM Beth, Rooms in New Orleans are very hard to come by during this period.  We are working on it. Best, Jo-Ann From: Beth L. Soliere [BLSoliere@azcc.gov] Sent: Friday, November 14, 2014 4:31 PM To: Mahoney, Jo-Ann Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions Hi Jo-Ann,   Just checking back. I didn’t hear back from Hannah.   Thanks,   Beth   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Monday, November 10, 2014 2:34 PM To: Beth L. Soliere Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions   Beth,  I will ask Hannah to do so when she returns to the office tomorrow.  Jo-Ann  How many days? From: Beth L. Soliere [BLSoliere@azcc.gov] Sent: Monday, November 10, 2014 4:30 PM To: Mahoney, Jo-Ann Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions Okay, no problem.  Could you get him a few extra days that he will pay for but would be for the same rate?   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Monday, November 10, 2014 2:18 PM To: Beth L. Soliere Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions   Yes.  They are on a wait list at the Windsor Court.   From: Beth L. Soliere [BLSoliere@azcc.gov] Sent: Monday, November 10, 2014 3:50 PM To: Mahoney, Jo-Ann Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions Okay, for both Bitter Smith and Stump?   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Monday, November 10, 2014 12:56 PM To: Beth L. Soliere Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions   Beth,   We have put the commissioners in a nearby hotel, the Sheraton, as this hotel has completely sold out.  I apologize for that.   Best, Jo-Ann From: Beth L. Soliere [BLSoliere@azcc.gov] Sent: Monday, November 10, 2014 12:57 PM To: Mahoney, Jo-Ann Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions Hi Jo-Ann,   Would it be possible for the hotel to extend the group rate to Chairman Stump for a few extra days following the meeting?   Thank you!   Beth   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Monday, November 03, 2014 12:43 PM To: Beth L. Soliere Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions   We have done so, Beth, and will send you a confirmation later in the week.   From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Monday, November 03, 2014 2:39 PM To: Mahoney, Jo-Ann Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions   Hi Jo-Ann,   I am wondering if you or Hannah can set Chairman Stump up with a hotel room at the Windsor Court?   Thank you,   Beth   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Tuesday, October 28, 2014 11:01 AM To: Mahoney, Jo-Ann Cc: Bruner, Hannah Subject: HEPG New Orleans: Deadline October 31, panel descriptions   Dear Commissioner,   We invite you to attend the next meeting of the Harvard Electricity Policy Group, scheduled to take place at the Windsor Court Hotel in New Orleans, Louisiana on Thursday-Friday, December 4-52014.  We will dedicate one discussion session to “Technology and Resource Choice:  What Value Diversity?, and one session to “Environmental Dispatch:  Now? Or Never?”  (Descriptions below.)  The third panel will be announced shortly.  For your planning purposes the meeting will convene on Thursday morning at breakfast (8:30 am) and adjourn at noon on Friday.  The conference reception and dinner will take place on Thursday evening.   We are able to cover travel expenses, within reason, and can arrange a room at the Windsor Court Hotel for Wednesday, December 3 and Thursday, December 4.    Kindly let us know by Friday, October 31, if you would like to attend.  We apologize for the short notice, as we were waiting to vet our conference topics.  I would like to take this opportunity to introduce you to Hannah Bruner, our new project assistant, who will be working with the commissioners on logistics.  She can be reached at 617-496-6760 (Hannah.Bruner@hks.harvard.edu).   We hope that you can join us in New Orleans.  Kindly return the conference registration form and request for a hotel room to Hannah Bruner’s attention.   Best, Jo-Ann   Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu   Technology and Resource Choice: What Value Diversity?   Natural gas has clearly become the “fuel of choice” for new generation in the United States,  That “choice,” of course was not dictated by policy, but, rather by the marketplace.  The competitors of gas, primarily coal, nuclear, and renewables, have been either more expensive, less reliable, or environmentally riskier, or perceived to have some combination of those market disadvantages.  The result has been what some have characterized as a market driven “rush to gas.” Some would contend that resource decisions need to better take into account the benefits of diversity in resources.  Prior to the emergence of competition, vertically integrated utilities, as well as regulators, through integrated planning processes could try to optimize such long and short time considerations. Is such an effort possible in a competitive market? Is it needed, or, over time will market forces balance things out? Renewables in many jurisdictions have their own set aside market, renewable portfolio standards.  Nuclear and coal, have no such set aside haven from the market. Should RTO planning processes be required to explicitly address portfolio diversity?  If so, what criteria should be used in forgoing currently knowable price information in favor of longer term insulation from volatility? What reasonable risks should a merchant generator be expected to take when it opts for a resource that is out of the market at present?  How would the costs of any above current market plants be allocated?  Are the prices for “out of market” resources actually brought back into the market by virtue of having fuel on site, or other reliability/systems operations perspectives? What would such a planning process do to the competitive nature of the marketplace?   Environmental Dispatch: Now? Or Never?   The notion of using environmental criteria to dispatch power plants has periodically arisen as an approach to reduce emissions.  The theory seems simple to some, namely that plants are to be dispatched on an emissions merit order basis, least emitting sources first, subject, of course to security constraints.  While the idea may be simple, actual implementation would raise many questions. What would environmental protocols look like?  How does one balance between economic and environmental merit orders?   How do incremental costs for out of economic merit order get allocated? How might such a system fit into Section 111(d) SIP’s? What impact would environmental dispatch have on LMPs and FTR markets? Would the standard market design collapse or adapt? Are all plants capable of operating in a fashion that would allow for emissions based dispatch, and if not, how should that be dealt with?  How do multi-state system operators dispatch in an environmental merit order when  various states may have different, if not conflicting, compliance programs?  How would emissions trading be altered by environmental dispatch? In short, how would such a system work and can it be done on a reasonable efficient basis? From: To: Subject: Date: Mahoney, Jo-Ann Beth L. Soliere RE: HEPG New Orleans: Deadline October 31, panel descriptions Monday, November 10, 2014 2:34:11 PM Beth,  I will ask Hannah to do so when she returns to the office tomorrow.  Jo-Ann  How many days? From: Beth L. Soliere [BLSoliere@azcc.gov] Sent: Monday, November 10, 2014 4:30 PM To: Mahoney, Jo-Ann Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions Okay, no problem.  Could you get him a few extra days that he will pay for but would be for the same rate?   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Monday, November 10, 2014 2:18 PM To: Beth L. Soliere Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions   Yes.  They are on a wait list at the Windsor Court.   From: Beth L. Soliere [BLSoliere@azcc.gov] Sent: Monday, November 10, 2014 3:50 PM To: Mahoney, Jo-Ann Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions Okay, for both Bitter Smith and Stump?   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Monday, November 10, 2014 12:56 PM To: Beth L. Soliere Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions   Beth,   We have put the commissioners in a nearby hotel, the Sheraton, as this hotel has completely sold out.  I apologize for that.   Best, Jo-Ann From: Beth L. Soliere [BLSoliere@azcc.gov] Sent: Monday, November 10, 2014 12:57 PM To: Mahoney, Jo-Ann Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions Hi Jo-Ann,   Would it be possible for the hotel to extend the group rate to Chairman Stump for a few extra days following the meeting?   Thank you!   Beth   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Monday, November 03, 2014 12:43 PM To: Beth L. Soliere Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions   We have done so, Beth, and will send you a confirmation later in the week.   From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Monday, November 03, 2014 2:39 PM To: Mahoney, Jo-Ann Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions   Hi Jo-Ann,   I am wondering if you or Hannah can set Chairman Stump up with a hotel room at the Windsor Court?   Thank you,   Beth   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Tuesday, October 28, 2014 11:01 AM To: Mahoney, Jo-Ann Cc: Bruner, Hannah Subject: HEPG New Orleans: Deadline October 31, panel descriptions   Dear Commissioner,   We invite you to attend the next meeting of the Harvard Electricity Policy Group, scheduled to take place at the Windsor Court Hotel in New Orleans, Louisiana on Thursday-Friday, December 4-52014.  We will dedicate one discussion session to “Technology and Resource Choice:  What Value Diversity?, and one session to “Environmental Dispatch:  Now? Or Never?”  (Descriptions below.)  The third panel will be announced shortly.  For your planning purposes the meeting will convene on Thursday morning at breakfast (8:30 am) and adjourn at noon on Friday.  The conference reception and dinner will take place on Thursday evening.   We are able to cover travel expenses, within reason, and can arrange a room at the Windsor Court Hotel for Wednesday, December 3 and Thursday, December 4.    Kindly let us know by Friday, October 31, if you would like to attend.  We apologize for the short notice, as we were waiting to vet our conference topics.  I would like to take this opportunity to introduce you to Hannah Bruner, our new project assistant, who will be working with the commissioners on logistics.  She can be reached at 617-496-6760 (Hannah.Bruner@hks.harvard.edu).   We hope that you can join us in New Orleans.  Kindly return the conference registration form and request for a hotel room to Hannah Bruner’s attention.   Best, Jo-Ann   Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu   Technology and Resource Choice: What Value Diversity?   Natural gas has clearly become the “fuel of choice” for new generation in the United States,  That “choice,” of course was not dictated by policy, but, rather by the marketplace.  The competitors of gas, primarily coal, nuclear, and renewables, have been either more expensive, less reliable, or environmentally riskier, or perceived to have some combination of those market disadvantages.  The result has been what some have characterized as a market driven “rush to gas.” Some would contend that resource decisions need to better take into account the benefits of diversity in resources.  Prior to the emergence of competition, vertically integrated utilities, as well as regulators, through integrated planning processes could try to optimize such long and short time considerations. Is such an effort possible in a competitive market? Is it needed, or, over time will market forces balance things out? Renewables in many jurisdictions have their own set aside market, renewable portfolio standards.  Nuclear and coal, have no such set aside haven from the market. Should RTO planning processes be required to explicitly address portfolio diversity?  If so, what criteria should be used in forgoing currently knowable price information in favor of longer term insulation from volatility? What reasonable risks should a merchant generator be expected to take when it opts for a resource that is out of the market at present?  How would the costs of any above current market plants be allocated?  Are the prices for “out of market” resources actually brought back into the market by virtue of having fuel on site, or other reliability/systems operations perspectives? What would such a planning process do to the competitive nature of the marketplace?   Environmental Dispatch: Now? Or Never?   The notion of using environmental criteria to dispatch power plants has periodically arisen as an approach to reduce emissions.  The theory seems simple to some, namely that plants are to be dispatched on an emissions merit order basis, least emitting sources first, subject, of course to security constraints.  While the idea may be simple, actual implementation would raise many questions. What would environmental protocols look like?  How does one balance between economic and environmental merit orders?   How do incremental costs for out of economic merit order get allocated? How might such a system fit into Section 111(d) SIP’s? What impact would environmental dispatch have on LMPs and FTR markets? Would the standard market design collapse or adapt? Are all plants capable of operating in a fashion that would allow for emissions based dispatch, and if not, how should that be dealt with?  How do multi-state system operators dispatch in an environmental merit order when  various states may have different, if not conflicting, compliance programs?  How would emissions trading be altered by environmental dispatch? In short, how would such a system work and can it be done on a reasonable efficient basis? From: To: Subject: Date: Mahoney, Jo-Ann Beth L. Soliere RE: HEPG New Orleans: Deadline October 31, panel descriptions Monday, November 10, 2014 2:18:17 PM Yes.  They are on a wait list at the Windsor Court.   From: Beth L. Soliere [BLSoliere@azcc.gov] Sent: Monday, November 10, 2014 3:50 PM To: Mahoney, Jo-Ann Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions Okay, for both Bitter Smith and Stump?   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Monday, November 10, 2014 12:56 PM To: Beth L. Soliere Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions   Beth,   We have put the commissioners in a nearby hotel, the Sheraton, as this hotel has completely sold out.  I apologize for that.   Best, Jo-Ann From: Beth L. Soliere [BLSoliere@azcc.gov] Sent: Monday, November 10, 2014 12:57 PM To: Mahoney, Jo-Ann Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions Hi Jo-Ann,   Would it be possible for the hotel to extend the group rate to Chairman Stump for a few extra days following the meeting?   Thank you!   Beth   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Monday, November 03, 2014 12:43 PM To: Beth L. Soliere Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions   We have done so, Beth, and will send you a confirmation later in the week.   From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Monday, November 03, 2014 2:39 PM To: Mahoney, Jo-Ann Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions   Hi Jo-Ann,   I am wondering if you or Hannah can set Chairman Stump up with a hotel room at the Windsor Court?   Thank you,   Beth   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Tuesday, October 28, 2014 11:01 AM To: Mahoney, Jo-Ann Cc: Bruner, Hannah Subject: HEPG New Orleans: Deadline October 31, panel descriptions   Dear Commissioner,   We invite you to attend the next meeting of the Harvard Electricity Policy Group, scheduled to take place at the Windsor Court Hotel in New Orleans, Louisiana on Thursday-Friday, December 4-52014.  We will dedicate one discussion session to “Technology and Resource Choice:  What Value Diversity?, and one session to “Environmental Dispatch:  Now? Or Never?”  (Descriptions below.)  The third panel will be announced shortly.  For your planning purposes the meeting will convene on Thursday morning at breakfast (8:30 am) and adjourn at noon on Friday.  The conference reception and dinner will take place on Thursday evening.   We are able to cover travel expenses, within reason, and can arrange a room at the Windsor Court Hotel for Wednesday, December 3 and Thursday, December 4.    Kindly let us know by Friday, October 31, if you would like to attend.  We apologize for the short notice, as we were waiting to vet our conference topics.  I would like to take this opportunity to introduce you to Hannah Bruner, our new project assistant, who will be working with the commissioners on logistics.  She can be reached at 617-496-6760 (Hannah.Bruner@hks.harvard.edu).   We hope that you can join us in New Orleans.  Kindly return the conference registration form and request for a hotel room to Hannah Bruner’s attention.   Best, Jo-Ann   Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu   Technology and Resource Choice: What Value Diversity?   Natural gas has clearly become the “fuel of choice” for new generation in the United States,  That “choice,” of course was not dictated by policy, but, rather by the marketplace.  The competitors of gas, primarily coal, nuclear, and renewables, have been either more expensive, less reliable, or environmentally riskier, or perceived to have some combination of those market disadvantages.  The result has been what some have characterized as a market driven “rush to gas.” Some would contend that resource decisions need to better take into account the benefits of diversity in resources.  Prior to the emergence of competition, vertically integrated utilities, as well as regulators, through integrated planning processes could try to optimize such long and short time considerations. Is such an effort possible in a competitive market? Is it needed, or, over time will market forces balance things out? Renewables in many jurisdictions have their own set aside market, renewable portfolio standards.  Nuclear and coal, have no such set aside haven from the market. Should RTO planning processes be required to explicitly address portfolio diversity?  If so, what criteria should be used in forgoing currently knowable price information in favor of longer term insulation from volatility? What reasonable risks should a merchant generator be expected to take when it opts for a resource that is out of the market at present?  How would the costs of any above current market plants be allocated?  Are the prices for “out of market” resources actually brought back into the market by virtue of having fuel on site, or other reliability/systems operations perspectives? What would such a planning process do to the competitive nature of the marketplace?   Environmental Dispatch: Now? Or Never?   The notion of using environmental criteria to dispatch power plants has periodically arisen as an approach to reduce emissions.  The theory seems simple to some, namely that plants are to be dispatched on an emissions merit order basis, least emitting sources first, subject, of course to security constraints.  While the idea may be simple, actual implementation would raise many questions. What would environmental protocols look like?  How does one balance between economic and environmental merit orders?   How do incremental costs for out of economic merit order get allocated? How might such a system fit into Section 111(d) SIP’s? What impact would environmental dispatch have on LMPs and FTR markets? Would the standard market design collapse or adapt? Are all plants capable of operating in a fashion that would allow for emissions based dispatch, and if not, how should that be dealt with?  How do multi-state system operators dispatch in an environmental merit order when  various states may have different, if not conflicting, compliance programs?  How would emissions trading be altered by environmental dispatch? In short, how would such a system work and can it be done on a reasonable efficient basis? From: To: Subject: Date: Teresa Tenbrink Beth L. Soliere RE: Monday, November 10, 2014 2:10:39 PM Oh terrific!!  We’ll see what they say to me.   Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   From: Beth L. Soliere Sent: Monday, November 10, 2014 1:56 PM To: Teresa Tenbrink Subject: RE:   But she never told me that until today when I asked….   From: Teresa Tenbrink Sent: Monday, November 10, 2014 1:54 PM To: Beth L. Soliere Subject: RE:   I requested the Windsor Court hotel but haven’t heard about confirmation #.  I’ve emailed for an update.   Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   From: Beth L. Soliere Sent: Monday, November 10, 2014 1:52 PM To: Teresa Tenbrink Subject: RE:   Did they put her in the Sheraton?   From: Teresa Tenbrink Sent: Monday, November 10, 2014 1:52 PM To: Beth L. Soliere Subject: RE:   Yep!   Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   From: Beth L. Soliere Sent: Monday, November 10, 2014 1:51 PM To: Teresa Tenbrink Subject:   Is Susan going to HEPG in New Orleans?   Beth Soliere, Executive Aide Chairman Bob Stump Arizona Corporation Commission 1200 W. Washington Street Phoenix, AZ 85007 602-542-3935   From: To: Subject: Date: Teresa Tenbrink Beth L. Soliere RE: Monday, November 10, 2014 1:54:13 PM I requested the Windsor Court hotel but haven’t heard about confirmation #.  I’ve emailed for an update.   Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   From: Beth L. Soliere Sent: Monday, November 10, 2014 1:52 PM To: Teresa Tenbrink Subject: RE:   Did they put her in the Sheraton?   From: Teresa Tenbrink Sent: Monday, November 10, 2014 1:52 PM To: Beth L. Soliere Subject: RE:   Yep!   Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   From: Beth L. Soliere Sent: Monday, November 10, 2014 1:51 PM To: Teresa Tenbrink Subject:   Is Susan going to HEPG in New Orleans?   Beth Soliere, Executive Aide Chairman Bob Stump Arizona Corporation Commission 1200 W. Washington Street Phoenix, AZ 85007 602-542-3935   From: To: Subject: Date: Teresa Tenbrink Beth L. Soliere RE: Monday, November 10, 2014 1:51:44 PM Yep!   Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   From: Beth L. Soliere Sent: Monday, November 10, 2014 1:51 PM To: Teresa Tenbrink Subject:   Is Susan going to HEPG in New Orleans?   Beth Soliere, Executive Aide Chairman Bob Stump Arizona Corporation Commission 1200 W. Washington Street Phoenix, AZ 85007 602-542-3935   From: To: Subject: Date: Mahoney, Jo-Ann Beth L. Soliere RE: HEPG New Orleans: Deadline October 31, panel descriptions Monday, November 10, 2014 12:55:38 PM Beth, We have put the commissioners in a nearby hotel, the Sheraton, as this hotel has completely sold out.  I apologize for that. Best, Jo-Ann From: Beth L. Soliere [BLSoliere@azcc.gov] Sent: Monday, November 10, 2014 12:57 PM To: Mahoney, Jo-Ann Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions Hi Jo-Ann,   Would it be possible for the hotel to extend the group rate to Chairman Stump for a few extra days following the meeting?   Thank you!   Beth   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Monday, November 03, 2014 12:43 PM To: Beth L. Soliere Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions   We have done so, Beth, and will send you a confirmation later in the week.   From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Monday, November 03, 2014 2:39 PM To: Mahoney, Jo-Ann Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions   Hi Jo-Ann,   I am wondering if you or Hannah can set Chairman Stump up with a hotel room at the Windsor Court?   Thank you,   Beth   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Tuesday, October 28, 2014 11:01 AM To: Mahoney, Jo-Ann Cc: Bruner, Hannah Subject: HEPG New Orleans: Deadline October 31, panel descriptions   Dear Commissioner,   We invite you to attend the next meeting of the Harvard Electricity Policy Group, scheduled to take place at the Windsor Court Hotel in New Orleans, Louisiana on Thursday-Friday, December 4-52014.  We will dedicate one discussion session to “Technology and Resource Choice:  What Value Diversity?, and one session to “Environmental Dispatch:  Now? Or Never?”  (Descriptions below.)  The third panel will be announced shortly.  For your planning purposes the meeting will convene on Thursday morning at breakfast (8:30 am) and adjourn at noon on Friday.  The conference reception and dinner will take place on Thursday evening.   We are able to cover travel expenses, within reason, and can arrange a room at the Windsor Court Hotel for Wednesday, December 3 and Thursday, December 4.    Kindly let us know by Friday, October 31, if you would like to attend.  We apologize for the short notice, as we were waiting to vet our conference topics.  I would like to take this opportunity to introduce you to Hannah Bruner, our new project assistant, who will be working with the commissioners on logistics.  She can be reached at 617-496-6760 (Hannah.Bruner@hks.harvard.edu).   We hope that you can join us in New Orleans.  Kindly return the conference registration form and request for a hotel room to Hannah Bruner’s attention.   Best, Jo-Ann   Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu   Technology and Resource Choice: What Value Diversity?   Natural gas has clearly become the “fuel of choice” for new generation in the United States,  That “choice,” of course was not dictated by policy, but, rather by the marketplace.  The competitors of gas, primarily coal, nuclear, and renewables, have been either more expensive, less reliable, or environmentally riskier, or perceived to have some combination of those market disadvantages.  The result has been what some have characterized as a market driven “rush to gas.” Some would contend that resource decisions need to better take into account the benefits of diversity in resources.  Prior to the emergence of competition, vertically integrated utilities, as well as regulators, through integrated planning processes could try to optimize such long and short time considerations. Is such an effort possible in a competitive market? Is it needed, or, over time will market forces balance things out? Renewables in many jurisdictions have their own set aside market, renewable portfolio standards.  Nuclear and coal, have no such set aside haven from the market. Should RTO planning processes be required to explicitly address portfolio diversity?  If so, what criteria should be used in forgoing currently knowable price information in favor of longer term insulation from volatility? What reasonable risks should a merchant generator be expected to take when it opts for a resource that is out of the market at present?  How would the costs of any above current market plants be allocated?  Are the prices for “out of market” resources actually brought back into the market by virtue of having fuel on site, or other reliability/systems operations perspectives? What would such a planning process do to the competitive nature of the marketplace?   Environmental Dispatch: Now? Or Never?   The notion of using environmental criteria to dispatch power plants has periodically arisen as an approach to reduce emissions.  The theory seems simple to some, namely that plants are to be dispatched on an emissions merit order basis, least emitting sources first, subject, of course to security constraints.  While the idea may be simple, actual implementation would raise many questions. What would environmental protocols look like?  How does one balance between economic and environmental merit orders?   How do incremental costs for out of economic merit order get allocated? How might such a system fit into Section 111(d) SIP’s? What impact would environmental dispatch have on LMPs and FTR markets? Would the standard market design collapse or adapt? Are all plants capable of operating in a fashion that would allow for emissions based dispatch, and if not, how should that be dealt with?  How do multi-state system operators dispatch in an environmental merit order when  various states may have different, if not conflicting, compliance programs?  How would emissions trading be altered by environmental dispatch? In short, how would such a system work and can it be done on a reasonable efficient basis? From: To: Subject: Date: Mahoney, Jo-Ann Beth L. Soliere RE: HEPG New Orleans: Deadline October 31, panel descriptions Monday, November 03, 2014 12:43:09 PM We have done so, Beth, and will send you a confirmation later in the week.   From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Monday, November 03, 2014 2:39 PM To: Mahoney, Jo-Ann Subject: RE: HEPG New Orleans: Deadline October 31, panel descriptions   Hi Jo-Ann,   I am wondering if you or Hannah can set Chairman Stump up with a hotel room at the Windsor Court?   Thank you,   Beth   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Tuesday, October 28, 2014 11:01 AM To: Mahoney, Jo-Ann Cc: Bruner, Hannah Subject: HEPG New Orleans: Deadline October 31, panel descriptions   Dear Commissioner,   We invite you to attend the next meeting of the Harvard Electricity Policy Group, scheduled to take place at the Windsor Court Hotel in New Orleans, Louisiana on Thursday-Friday, December 4-52014.  We will dedicate one discussion session to “Technology and Resource Choice:  What Value Diversity?, and one session to “Environmental Dispatch:  Now? Or Never?”  (Descriptions below.)  The third panel will be announced shortly.  For your planning purposes the meeting will convene on Thursday morning at breakfast (8:30 am) and adjourn at noon on Friday.  The conference reception and dinner will take place on Thursday evening.   We are able to cover travel expenses, within reason, and can arrange a room at the Windsor Court Hotel for Wednesday, December 3 and Thursday, December 4.    Kindly let us know by Friday, October 31, if you would like to attend.  We apologize for the short notice, as we were waiting to vet our conference topics.  I would like to take this opportunity to introduce you to Hannah Bruner, our new project assistant, who will be working with the commissioners on logistics.  She can be reached at 617-496-6760 (Hannah.Bruner@hks.harvard.edu).   We hope that you can join us in New Orleans.  Kindly return the conference registration form and request for a hotel room to Hannah Bruner’s attention.   Best, Jo-Ann   Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu   Technology and Resource Choice: What Value Diversity?   Natural gas has clearly become the “fuel of choice” for new generation in the United States,  That “choice,” of course was not dictated by policy, but, rather by the marketplace.  The competitors of gas, primarily coal, nuclear, and renewables, have been either more expensive, less reliable, or environmentally riskier, or perceived to have some combination of those market disadvantages.  The result has been what some have characterized as a market driven “rush to gas.” Some would contend that resource decisions need to better take into account the benefits of diversity in resources.  Prior to the emergence of competition, vertically integrated utilities, as well as regulators, through integrated planning processes could try to optimize such long and short time considerations. Is such an effort possible in a competitive market? Is it needed, or, over time will market forces balance things out? Renewables in many jurisdictions have their own set aside market, renewable portfolio standards.  Nuclear and coal, have no such set aside haven from the market. Should RTO planning processes be required to explicitly address portfolio diversity?  If so, what criteria should be used in forgoing currently knowable price information in favor of longer term insulation from volatility? What reasonable risks should a merchant generator be expected to take when it opts for a resource that is out of the market at present?  How would the costs of any above current market plants be allocated?  Are the prices for “out of market” resources actually brought back into the market by virtue of having fuel on site, or other reliability/systems operations perspectives? What would such a planning process do to the competitive nature of the marketplace?   Environmental Dispatch: Now? Or Never?   The notion of using environmental criteria to dispatch power plants has periodically arisen as an approach to reduce emissions.  The theory seems simple to some, namely that plants are to be dispatched on an emissions merit order basis, least emitting sources first, subject, of course to security constraints.  While the idea may be simple, actual implementation would raise many questions. What would environmental protocols look like?  How does one balance between economic and environmental merit orders?   How do incremental costs for out of economic merit order get allocated? How might such a system fit into Section 111(d) SIP’s? What impact would environmental dispatch have on LMPs and FTR markets? Would the standard market design collapse or adapt? Are all plants capable of operating in a fashion that would allow for emissions based dispatch, and if not, how should that be dealt with?  How do multi-state system operators dispatch in an environmental merit order when  various states may have different, if not conflicting, compliance programs?  How would emissions trading be altered by environmental dispatch? In short, how would such a system work and can it be done on a reasonable efficient basis? From: To: Subject: Date: Bob Stump Beth L. Soliere Re: Invitation to Attend HEPG"s Dec. 2014 Session Thursday, October 30, 2014 1:29:15 PM Ah yes. So many rsvps. Thanks.  On Thursday, October 30, 2014, Beth L. Soliere wrote: Do you want to go? Sent from my iPhone Begin forwarded message: From: "Bruner, Hannah" > Date: October 30, 2014 at 1:10:34 PM EDT To: "Beth L. Soliere" > Subject: Invitation to Attend HEPG's Dec. 2014 Session Dear Beth, Our registration deadline for HEPG’s December 2014 session in New Orleans, LA is quickly approaching. We were to extend the registration deadline to Monday, November 3 at 12:00 pm. However, the hotel will not allow us any more leeway. We would be delighted if Commissioner Stump could attend. We have a great list of attendees this session—among them, Commissioner LaFleur and Commissioner Bay—that are sure to foster productive and interesting discussion. The conference will take place at the Windsor Court Hotel in New Orleans on Thursday and Friday, December 4-5, 2014. The session will convene on Thursday morning at breakfast (8:30 am) and adjourn at noon on Friday.  The conference reception and dinner will take place on Thursday evening. We will dedicate one discussion session to “Technology and Resource Choice:  What Value Diversity?” and one session to “Environmental Dispatch:  Now? Or Never?” Please see the panel descriptions below. The third panel will be announced shortly. We will, of course, cover travel expenses, within reason, and arrange a room at the Windsor Court Hotel for Wednesday, December 3 and Thursday, December 4. Kindly, advise me of your plans as soon as possible, so we can reserve your space. We hope to see Commissioner Stump at the conference! It is sure to be a good time. Warm regards, Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu Technology and Resource Choice: What Value Diversity? Natural gas has clearly become the “fuel of choice” for new generation in the United States,  That “choice,” of course was not dictated by policy, but, rather by the marketplace.  The competitors of gas, primarily coal, nuclear, and renewables, have been either more expensive, less reliable, or environmentally riskier, or perceived to have some combination of those market disadvantages.  The result has been what some have characterized as a market driven “rush to gas.” Some would contend that resource decisions need to better take into account the benefits of diversity in resources.  Prior to the emergence of competition, vertically integrated utilities, as well as regulators, through integrated planning processes could try to optimize such long and short time considerations. Is such an effort possible in a competitive market? Is it needed, or, over time will market forces balance things out? Renewables in many jurisdictions have their own set aside market, renewable portfolio standards.  Nuclear and coal, have no such set aside haven from the market. Should RTO planning processes be required to explicitly address portfolio diversity?  If so, what criteria should be used in forgoing currently knowable price information in favor of longer term insulation from volatility? What reasonable risks should a merchant generator be expected to take when it opts for a resource that is out of the market at present?  How would the costs of any above current market plants be allocated?  Are the prices for “out of market” resources actually brought back into the market by virtue of having fuel on site, or other reliability/systems operations perspectives? What would such a planning process do to the competitive nature of the marketplace? Environmental Dispatch: Now? Or Never? The notion of using environmental criteria to dispatch power plants has periodically arisen as an approach to reduce emissions.  The theory seems simple to some, namely that plants are to be dispatched on an emissions merit order basis, least emitting sources first, subject, of course to security constraints.  While the idea may be simple, actual implementation would raise many questions. What would environmental protocols look like?  How does one balance between economic and environmental merit orders?   How do incremental costs for out of economic merit order get allocated? How might such a system fit into Section 111(d) SIP’s? What impact would environmental dispatch have on LMPs and FTR markets? Would the standard market design collapse or adapt? Are all plants capable of operating in a fashion that would allow for emissions based dispatch, and if not, how should that be dealt with?  How do multi-state system operators dispatch in an environmental merit order when  various states may have different, if not conflicting, compliance programs?  How would emissions trading be altered by environmental dispatch? In short, how would such a system work and can it be done on a reasonable efficient basis? -Bob Stump Chair, Phoenix Opera 3120 West Carefree Highway, Suite 1-106 Phoenix, AZ 85086   Chair, Arizona Corporation Commission 1200 W. Washington Phoenix, AZ  85007 602-542-3935 From: To: Subject: Date: Bruner, Hannah Beth L. Soliere Invitation to Attend HEPG"s Dec. 2014 Session Thursday, October 30, 2014 10:10:50 AM Dear Beth,   Our registration deadline for HEPG’s December 2014 session in New Orleans, LA is quickly approaching. We were to extend the registration deadline to Monday, November 3 at 12:00 pm. However, the hotel will not allow us any more leeway.   We would be delighted if Commissioner Stump could attend.   We have a great list of attendees this session—among them, Commissioner LaFleur and Commissioner Bay—that are sure to foster productive and interesting discussion.   The conference will take place at the Windsor Court Hotel in New Orleans on Thursday and Friday, December 4-5, 2014. The session will convene on Thursday morning at breakfast (8:30 am) and adjourn at noon on Friday.  The conference reception and dinner will take place on Thursday evening. We will dedicate one discussion session to “Technology and Resource Choice:  What Value Diversity?” and one session to “Environmental Dispatch:  Now? Or Never?” Please see the panel descriptions below. The third panel will be announced shortly.    We will, of course, cover travel expenses, within reason, and arrange a room at the Windsor Court Hotel for Wednesday, December 3 and Thursday, December 4.   Kindly, advise me of your plans as soon as possible, so we can reserve your space.   We hope to see Commissioner Stump at the conference! It is sure to be a good time.   Warm regards,     Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu   Technology and Resource Choice: What Value Diversity?   Natural gas has clearly become the “fuel of choice” for new generation in the United States,  That “choice,” of course was not dictated by policy, but, rather by the marketplace.  The competitors of gas, primarily coal, nuclear, and renewables, have been either more expensive, less reliable, or environmentally riskier, or perceived to have some combination of those market disadvantages.  The result has been what some have characterized as a market driven “rush to gas.” Some would contend that resource decisions need to better take into account the benefits of diversity in resources.  Prior to the emergence of competition, vertically integrated utilities, as well as regulators, through integrated planning processes could try to optimize such long and short time considerations. Is such an effort possible in a competitive market? Is it needed, or, over time will market forces balance things out? Renewables in many jurisdictions have their own set aside market, renewable portfolio standards.  Nuclear and coal, have no such set aside haven from the market. Should RTO planning processes be required to explicitly address portfolio diversity?  If so, what criteria should be used in forgoing currently knowable price information in favor of longer term insulation from volatility? What reasonable risks should a merchant generator be expected to take when it opts for a resource that is out of the market at present?  How would the costs of any above current market plants be allocated?  Are the prices for “out of market” resources actually brought back into the market by virtue of having fuel on site, or other reliability/systems operations perspectives? What would such a planning process do to the competitive nature of the marketplace?   Environmental Dispatch: Now? Or Never?   The notion of using environmental criteria to dispatch power plants has periodically arisen as an approach to reduce emissions.  The theory seems simple to some, namely that plants are to be dispatched on an emissions merit order basis, least emitting sources first, subject, of course to security constraints.  While the idea may be simple, actual implementation would raise many questions. What would environmental protocols look like?  How does one balance between economic and environmental merit orders?   How do incremental costs for out of economic merit order get allocated? How might such a system fit into Section 111(d) SIP’s? What impact would environmental dispatch have on LMPs and FTR markets? Would the standard market design collapse or adapt? Are all plants capable of operating in a fashion that would allow for emissions based dispatch, and if not, how should that be dealt with?  How do multi-state system operators dispatch in an environmental merit order when  various states may have different, if not conflicting, compliance programs?  How would emissions trading be altered by environmental dispatch? In short, how would such a system work and can it be done on a reasonable efficient basis?     From: To: Cc: Subject: Date: Attachments: Mahoney, Jo-Ann Mahoney, Jo-Ann Bruner, Hannah HEPG New Orleans: Deadline October 31, panel descriptions Tuesday, October 28, 2014 11:02:10 AM Registration_form_comm_12_14.docx Dear Commissioner,   We invite you to attend the next meeting of the Harvard Electricity Policy Group, scheduled to take place at the Windsor Court Hotel in New Orleans, Louisiana on Thursday-Friday, December 4-52014.  We will dedicate one discussion session to “Technology and Resource Choice:  What Value Diversity?, and one session to “Environmental Dispatch:  Now? Or Never?”  (Descriptions below.)  The third panel will be announced shortly.  For your planning purposes the meeting will convene on Thursday morning at breakfast (8:30 am) and adjourn at noon on Friday.  The conference reception and dinner will take place on Thursday evening.   We are able to cover travel expenses, within reason, and can arrange a room at the Windsor Court Hotel for Wednesday, December 3 and Thursday, December 4.    Kindly let us know by Friday, October 31, if you would like to attend.  We apologize for the short notice, as we were waiting to vet our conference topics.  I would like to take this opportunity to introduce you to Hannah Bruner, our new project assistant, who will be working with the commissioners on logistics.  She can be reached at 617-496-6760 (Hannah.Bruner@hks.harvard.edu).   We hope that you can join us in New Orleans.  Kindly return the conference registration form and request for a hotel room to Hannah Bruner’s attention.   Best, Jo-Ann   Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu   Technology and Resource Choice: What Value Diversity?   Natural gas has clearly become the “fuel of choice” for new generation in the United States,  That “choice,” of course was not dictated by policy, but, rather by the marketplace.  The competitors of gas, primarily coal, nuclear, and renewables, have been either more expensive, less reliable, or environmentally riskier, or perceived to have some combination of those market disadvantages.  The result has been what some have characterized as a market driven “rush to gas.” Some would contend that resource decisions need to better take into account the benefits of diversity in resources.  Prior to the emergence of competition, vertically integrated utilities, as well as regulators, through integrated planning processes could try to optimize such long and short time considerations. Is such an effort possible in a competitive market? Is it needed, or, over time will market forces balance things out? Renewables in many jurisdictions have their own set aside market, renewable portfolio standards.  Nuclear and coal, have no such set aside haven from the market. Should RTO planning processes be required to explicitly address portfolio diversity?  If so, what criteria should be used in forgoing currently knowable price information in favor of longer term insulation from volatility? What reasonable risks should a merchant generator be expected to take when it opts for a resource that is out of the market at present?  How would the costs of any above current market plants be allocated?  Are the prices for “out of market” resources actually brought back into the market by virtue of having fuel on site, or other reliability/systems operations perspectives? What would such a planning process do to the competitive nature of the marketplace?   Environmental Dispatch: Now? Or Never?   The notion of using environmental criteria to dispatch power plants has periodically arisen as an approach to reduce emissions.  The theory seems simple to some, namely that plants are to be dispatched on an emissions merit order basis, least emitting sources first, subject, of course to security constraints.  While the idea may be simple, actual implementation would raise many questions. What would environmental protocols look like?  How does one balance between economic and environmental merit orders?   How do incremental costs for out of economic merit order get allocated? How might such a system fit into Section 111(d) SIP’s? What impact would environmental dispatch have on LMPs and FTR markets? Would the standard market design collapse or adapt? Are all plants capable of operating in a fashion that would allow for emissions based dispatch, and if not, how should that be dealt with?  How do multi-state system operators dispatch in an environmental merit order when  various states may have different, if not conflicting, compliance programs?  How would emissions trading be altered by environmental dispatch? In short, how would such a system work and can it be done on a reasonable efficient basis? REGISTRATION FORM HEPG SEVENTY-SEVENTH PLENARY SESSION THURSDAY AND FRIDAY, DECEMBER 4-5, 2014 WINDSOR COURT HOTEL NEW ORLEANS, LOUISIANA TO: HARVARD ELECTRICITY POLICY GROUP John F. Kennedy School of Government FROM: Name Title Affiliation Address Phone E-mail ______YES, I will be able to attend the HEPG Plenary Session. ______ NO, I will not be able to attend the meeting. ______ I would like to send my designee: Name Title Address Phone E-mail ___________________________ ___________________________ ___________________________ ___________________________ ___________________________ ___________________________ HOTEL INFORMATION We have reserved a block of rooms at the Windsor Court Hotel for the evenings of Wednesday, December 3 and Thursday, December 4. Please arrange your reservation through Hannah Bruner in the Harvard Electricity Policy Group: Hannah.Bruner@hks.harvard.edu. The Windsor Court Hotel is located at 300 Gravier Street in New Orleans. Reservation deadline: November 3, 2014. (Please note that the Windsor Court has a 14-day cancellation policy.) To register for the session, please fax or e-mail this reply form to: Hannah Bruner, HEPG Assistant Fax: (617) 495-1635 Phone: (617) 495-1390 email to: jo-ann_mahoney@harvard.edu From: To: Subject: Date: Bruner, Hannah Beth L. Soliere RE: HEPG Conference Registration Monday, October 27, 2014 8:54:24 AM I did--thank you. I submitted it to Finance to  be processed this morning. Best, Hannah -----Original Message----From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Monday, October 27, 2014 11:50 AM To: Bruner, Hannah Subject: Re: HEPG Conference Registration Will do. Did you receive the reimbursement form I sent over? Sent from my iPhone > On Oct 27, 2014, at 11:42 AM, "Bruner, Hannah" wrote: > > Hello, Beth, > You are right--thank you for keeping me straight. Please do let us know if he decides to attend! > Thank you. > Best wishes, > Hannah > > -----Original Message----> From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] > Sent: Monday, October 27, 2014 11:38 AM > To: Bruner, Hannah > Subject: Re: HEPG Conference Registration > > Hi Hannah, > > I am not sure that we registered for this. Although, I do think he plans to attend. > > Sent from my iPhone > > On Oct 27, 2014, at 11:36 AM, "Bruner, Hannah" > wrote: > > Good morning, > Thank you for registering for HEPG’s December 2014 conference. We have received your registration form and look forward to seeing you in New Orleans. > If you have any questions or if I can be of assistance, please do not hesitate to contact me. > Have a lovely day. > Warm regards, > > > Hannah Bruner > Staff Assistant > Harvard Electricity Policy Group > Harvard Kennedy School > (617) 496-6760 Brunet hks.harvard.edu> From: To: Subject: Date: Bruner, Hannah Beth L. Soliere RE: HEPG Conference Registration Monday, October 27, 2014 8:42:30 AM Hello, Beth, You are right--thank you for keeping me straight. Please do let us know if he decides to attend! Thank you. Best wishes, Hannah -----Original Message----From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Monday, October 27, 2014 11:38 AM To: Bruner, Hannah Subject: Re: HEPG Conference Registration Hi Hannah, I am not sure that we registered for this. Although, I do think he plans to attend. Sent from my iPhone On Oct 27, 2014, at 11:36 AM, "Bruner, Hannah" > wrote: Good morning, Thank you for registering for HEPG’s December 2014 conference. We have received your registration form and look forward to seeing you in New Orleans. If you have any questions or if I can be of assistance, please do not hesitate to contact me. Have a lovely day. Warm regards, Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu From: To: Subject: Date: Bruner, Hannah Beth L. Soliere HEPG Conference Registration Monday, October 27, 2014 8:36:34 AM Good morning, Thank you for registering for HEPG’s December 2014 conference. We have received your registration form and look forward to seeing you in New Orleans. If you have any questions or if I can be of assistance, please do not hesitate to contact me. Have a lovely day. Warm regards,     Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu   From: To: Subject: Date: Attachments: Bruner, Hannah Beth L. Soliere RE: Thursday, October 23, 2014 7:51:40 AM image001.png image002.png non-employee reimbursement.pdf Dear Beth, Good morning. Hotel should have already been paid by HEPG. We will reimburse you for airfare, taxi, and meals (as long as the meals are reasonable). I’ve attached the Non-Employee Reimbursement Form we need completed. If possible, please mail the original receipts to me at the following address:                 Hannah Bruner                 Staff Assistant/HEPG                 79 JFK St.                 Mailbox #84                 Cambridge, MA 02138 Some people have been having trouble opening the Non-Employee Reimbursement Form, so I’m also going to paste it within the body of this email. If I can help in any way or if you have any questions, please don’t hesitate to reach out to me. Have a great day! Warm regards, Hannah Bruner   . I Harvard University 5 Non Employee Reimbursement Form University Financial Services i 1033 Massachusetts Ave, 2nd Floor Cambridge MA 02133 Request Date: NR Number Heimhursee Na me: Requisition ifa Af?liation anvited Guest Harvard Student ?DtheriEsplain below} HU'DiAf?ll?lE5lii' Other Explanation I US. Citizen er Permanent Resident yes ?a Federal Spenered Funds Yes No Dates of Business Purpose: Provide detailed reasons and date ranges for expenditures. Travel and entertainment EXPENSEISJ expenses require the persenis] aner organization and location. ALL expenses must be itemized. #1 #2 #3 ELL MUST BE ITEMIZED LEE: THAN 575 WEGR HEW Description idate. details. mi Airmail Lodging Other Total #1 i! #2 #3 Sub-Tetal expenses from page 2 Total Reimbursement Total amount under $75 itemized in Total Reimbursement I certify these are valid business expenses on hehalfnf Harvard Reimbursee Signature:* I . Reimbursee Check Mailing Prepared I I phones I I You agree no unallerwahle costs. including undocumented expenses under $15, are being charged to Federal Funds as specified it OMB Circulars A-11 and lit-22. Approved I I Phones I I TO EXPEDITE PAYM ENT, PLEASE RETURN COMPLETED FORM AND REQUIRED DOCUMENTATION TCII THE UNIT FOR . PROCESSING TH ELECTRONIC REQUEST Required Field   From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Wednesday, October 22, 2014 4:22 PM To: Bruner, Hannah Subject:   Hi Hannah,   The approved reimbursements are airfare, hotel and taxi right? Are meals included?   Thanks!   Beth Soliere, Executive Aide Chairman Bob Stump Arizona Corporation Commission 1200 W. Washington Street Phoenix, AZ 85007 602-542-3935   . HarvardUnieersity 3-H Nun Employee Reimbursement Ferrn University Financial Services 1133 Massachusetts Ave. 2nd Fleer Cambridge. MA 02133 Request Date: HR Numb-er Reimbursee Name: Requisitien Af?liate" Invited Guest r} Ha ward Student {:i-Dthm [Explain below} i?f?'ial?i?? ?t her Explanatiein U.S. Citizen er Permanent Resident ?r'es Ne Federal Spenered Funds (3, Yes (3. Ne Dates at Business Purpose: Preside detailed reasens and date ranges fer expenditures. Travel and entertainment expenses require the persenis] andi?er erganizatien and lecatlen- ALL expenses must be itemized. #2 . I- #3 ENSES MUST BE TEM THAN 3'5 WE HEW Descriptien idate. details. etc] Airr'Rall 5mm? Emma? Other Tutsi Trans Meals I It #1 #2 #3 Su b-Tetal expenses Frem page 2 Total Reimbursement Total amount under $15 itemized in Tetal Reimbursement I I I certify these are valid business expenses {m behalf elf Harvard University Fieimbursee Signature? . Reimbursee Check Mailing Address:ill Prepared By {Print}: one - Teu agree nu unallewahle nests. including undesurnented expenses under 51's, are being charged to Federal Funds as specified it i Ciritulers 11-21 end. 11-22. Appear-red By {Plinth Phene TD EHPEDITE PAYMENT. PLEASE RETURN FORM AND REQUIRED MENTATIDN TO THE UNIT FDR . . PRDCESSINE THE ELECTRONIC REQUEST Required Field - i Nun Employee Reimbursement Helm bursee Harrie: Additiunal Expenses Heqmsitipn lr: Page 2 Descriptipn {plat-e. detailst etc} #4 iAirr?Fiail Ludging Ground Trans Business Meals ?ther Total #b-Tetal Reimbursement Line Distributiun Bu?nessFurpose# Arnuunt Tub Ubjept Fund Activity Sub Heat *Flequlred Field HINTS AND POLICY NDTES: Please refer to mmtravelhewardedu fer complete policy. This completed term and required dpeu mentetipn must be returned tn the Intel unit fer processing. steepest?Fest is Ellil?l?l Il??wmizm?h,? . Harvard University on Em ployee Relm bu rsement Form University Financial Services - 1033 Massachusetts Ave, 2nd Floor Cambridge, MA 02138 Request Date: NR Number*: Reimbursee Name: Requisition Affiliation 0 Invited Guest Harvard Student OOther (Explain below) HUID (Affiliates):* Other Explanation US. Citizen orPermanent Resident QYes ONO FederaISponored Funds ?CiYes ONO Dates of Business Purpose: Provide detailed reasons and date ranges for expenditures. Travel and entertainment Expense(5) expenses require the person(s) and/or organization and location. ALL expenses must be itemized. #1 #2 #3 ALL EXPENSES MUST BE ITEMIZED INCLUDING EXPENSES LESS THAN $75 (A DETAILED ITEMIZED LIST FOR EXPENSES LESS THAN $75 CAN BE ATTACHED To THIS FORM) Description (date, details, etc) Air/Rail Lodging Bub/11229555 Other Total #1 #2 #3 Sub-Total expenses from page 2 Total Reimbursement rh Total amount under $75 itemized in Total Reimbursement I certify these are valid business expenses on behalf of Harvard University Reimbursee Signature:* Reimbursee Check Mailing Address:* Prepared By (Print): Phone You agree no unallowable costs, including undocumented expenses under $75, are being charged to Federal Funds as specified in 0MB Circulars A-21 and A-22. Approved By (Print): Phone TO EXPEDITE PAYMENT, PLEASE RETURN COMPLETED FORM AND REQUIRED DOCUMENTATION TO THE UNIT RESPONSIBLE FOR . . PROCESSING THE ELECTRONIC REQUEST *Requlred Field Elli Page 2 terms? Non Employee Relmbursement Form Reimbursee Name: Req?JiSition Additional Expenses Description (date details etc) Air/Rail Lodging Ground Business Other Total Trans Meals Sub-Total Reimbursement Line Distribution Business Purpose Amount Tub Org Object Fund Activity Sub Root *Required Field HINTS AND POLICY NOTES: Please refer to for complete policy. This completed form and required documentation must be returned to the local unit for processing. It? From: To: Cc: Subject: Date: Mahoney, Jo-Ann Beth L. Soliere Bruner, Hannah RE: HEPG Dinner Choice: RSVP noon Wed Wednesday, October 22, 2014 11:31:39 AM Hi Beth,   Hannah Bruner in our office can help you with Chairman Stump’s reimbursement for the HEPG Cambridge session.   Best, Jo-Ann   From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Wednesday, October 22, 2014 2:06 PM To: Mahoney, Jo-Ann Subject: RE: HEPG Dinner Choice: RSVP noon Wed   Hi Jo-Ann,   Do you have a form you would like filled out for the travel reimbursement from the last trip?   Thanks,   Beth   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Tuesday, September 30, 2014 12:20 PM To: Mahoney, Jo-Ann Subject: HEPG Dinner Choice: RSVP noon Wed   Kindly let us know if you would prefer Tenderloin or fish (Char) for dinner on Thursday evening.  RSVP by noon tomorrow.  Thank you.   Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu     From: To: Subject: Date: Attachments: Bruner, Hannah Bob Stump Reimbursement for HEPG Oct. Session Monday, October 20, 2014 9:34:08 AM Non-Employee Reimbursement Form.pdf Dear Chairman Stump,   Good afternoon.   On behalf of the Harvard Electricity Policy Group, I would like to thank you for your participation in HEPG’s October 2014 Conference.   Please complete the attached Non-Employee Reimbursement Form, so we may send you your conference travel reimbursement. If you have any questions about the form, please do not hesitate to contact me at Hannah_Bruner@hks.harvard.edu.   Also, the Harvard Kennedy School requires original receipts for reimbursements. Please mail them to me:             Hannah Bruner             Harvard Electricity Policy Group             79 JFK St.             Mailbox 84             Cambridge, MA 02138   Thank you again.   Warm regards,     Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu   From: To: Subject: Date: Mahoney, Jo-Ann Mahoney, Jo-Ann HEPG Dinner Choice: RSVP noon Wed Tuesday, September 30, 2014 12:19:30 PM Kindly let us know if you would prefer Tenderloin or fish (Char) for dinner on Thursday evening.  RSVP by noon tomorrow.  Thank you.   Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 617-495-1390 Jo-ann_mahoney@hks.harvard.edu     From: To: Subject: Date: Bostian, Trudi Beth L. Soliere RE: HEPG Dinner? Thursday, June 26, 2014 8:36:18 AM October 2-3 December 4-5   This is subject to change, of course, but that’s the information that I have right now.   Thanks.   ******************************* Trudi R. Bostian Staff Assistant Harvard Electricity Policy Group 79 John F. Kennedy Street Cambridge, MA 02138 P: 617-496-6760 E: trudi_bostian@hks.harvard.edu   From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Wednesday, June 25, 2014 4:58 PM To: Bostian, Trudi Subject: RE: HEPG Dinner?   Hi Trudi,   Is there another meeting coming up in October?   From: Bostian, Trudi [mailto:Trudi_Bostian@hks.harvard.edu] Sent: Monday, June 02, 2014 7:20 AM To: Bob Stump; Beth L. Soliere Subject: HEPG Dinner?   Hi Bob,   Please let me know if you’ll be joining us for dinner on June 12th?   Thank you.   ******************************* Trudi R. Bostian Staff Assistant Harvard Electricity Policy Group 79 John F. Kennedy Street Cambridge, MA 02138 P: 617-496-6760 E: trudi_bostian@hks.harvard.edu   ========================================== This footnote confirms that this email message has been scanned to detect malicious content. If you experience problems, please e-mail postmaster@azcc.gov ========================================== From: To: Subject: Date: Attachments: Bostian, Trudi kenneth.anderson@puc.texas.gov; Monica.Lambert@puc.texas.gov; Rich.Wakeland@puc.texas.gov; Susan Bitter Smith; Teresa Tenbrink; jcolgan@icc.illinois.gov; cweller@icc.illinois.gov; jeanne.fox@bpu.state.nj.us; deborah.laird@bpu.state.nj.us; r.csira@bpu.state.nj.us; neil.jamieson@auc.ab.ca; pjones@wutc.wa.gov; dholman@utc.wa.gov; tkavulla@mt.gov; amccabe@icc.illinois.gov; cweller@icc.illinois.gov; donna.nelson@puc.texas.gov; Lisa.Cantu@puc.texas.gov; catherine.sandoval@cpuc.ca.gov; annchristina.rothchild@cpuc.ca.gov; Bob Stump; Beth L. Soliere Reimbursement for last week"s HEPG session Tuesday, June 17, 2014 8:18:21 AM universal_expense_form.pdf missing_receipt.pdf Hello,   It was wonderful to see all of you in Cambridge last week, and I hope you benefited from the conference and the discussions.   In order to receive reimbursement for your travel expenses, I will need you to follow these steps.   If Harvard is reimbursing you personally: Please fill out the attached Universal Expense Form and send this to me, along with original copies of your receipts. If you do not have receipts, or if you prefer to send scans via email, please also fill out the attached missing receipt affidavit.   If Harvard is reimbursing your organization: Please submit an invoice, on official letterhead, outlining the specific charges incurred and preferred method of payment.  Please also send me original receipts, and include a signed missing receipt affidavit if you use scans or if any receipts are missing.   Let me know if you have any questions or concerns.    ******************************* Trudi R. Bostian Staff Assistant Harvard Electricity Policy Group 79 John F. Kennedy Street Cambridge, MA 02138 P: 617-496-6760 E: trudi_bostian@hks.harvard.edu   HARVARD UNIVERSITY UNIVERSAL EXPENSE FORM EMPLOYEE TYPE OR AFFILIATION ❏ ❏ ❏ PAYMENT TYPE (CHECK ONLY ONE) Affiliate/Harvard Student/Casual/Stipend - complete shaded areas ❏ Out of Pocket ❏ American Express Corporate Card Invited Guest/Visitor - complete shaded areas Reimbursement Method (Check only one) Harvard Employee ❏ Direct Deposit ❏ Paper Check Date: Reimbursee or Cardholder Name: Social Sec/Tax ID#: Harvard ID#: Web Voucher/PO#: US Citizen or Permanent Resident: _______Yes _______ No Permanent Residents - Resident Alien Card # _____________ If you are not a US Citizen or Permanent Resident, provide: Visa Type: Country of Tax Residency: BUSINESS PURPOSE (Detailed reason for expenditure. For travel or entertainment, include person and/or organization visited and location. Also include expense date range. List additional business purposes on page 2.) Date(s) of expense(s) #1 #2 #3 #4 #5 SUMMARY OF EXPENSES (Room for additional expenses is available on page 2) Business Purpose# Description (date, detail, etc…) Air/Rail Travel Ground Trans. Lodging Business Meals Other Total Subtotals from page 2, if applicable: LESS ADVANCES EXPENSE REPORT TOTAL: TOTAL AMOUNT OF RECEIPTS UNDER $75 $ $ $ REIMBURSEE: I certify that these are all legitimate Harvard University business expenses. SIGNATURE: Date: Reimbursee Permanent Legal Address: Reimbursee Check Mailing Address, if different than Legal: I have reviewed these expenses and all are in accordance with University and Tub policy. Preparer: __________________________________ Phone: ___________ Approver: ___________________________________ 1 (PRINT) (SIGNATURE) HARVARD UNIVERSITY UNIVERSAL EXPENSE FORM – SUPPLEMENTAL INFORMATION PAGE ____OF ___ Reimbursee or Cardholder Name: Web Voucher/PO#: Departmental Accounting The area below is for departments whose financial office requires this information for processing purposes. This information will be captured in the Web Voucher System. Business Purpose# Amount Tub (3) Org (5) Object (4) Fund (6) Activity (6) Sub (4) Root (5) $ ADDITIONAL BUSINESS PURPOSES OR INFORMATION Date(s) of expense(s) #6 #7 #8 #9 ADDITIONAL EXPENSES Business Purpose# Description (date, detail, etc.) Air/Rail Travel Ground Trans Lodging Business Meals Other Total Subtotals, carry to first sheet Hints and policy notes: 1. 2. 3. 2 You may attach an AMEX statement in lieu of completing the description section. Cross-reference business purpose to each item on the statement by writing the business purpose # next to the itemized lines. Please refer to the Policy at a Glance or the complete travel policy at www.travel.harvard.edu. To expedite processing, contact the Travel Office at 495-7760 with policy questions prior to submitting this form. pcard, mra, lost, forgot, print, form, documentation, required HARVARD UNIVERSITY MISSING RECEIPT AFFIDAVIT Please read the Missing Receipt Affidavit requirements on the back of this form. Missing Receipt Affidavits lacking the required information or documentation will be returned to the authorized signer. Airline Ticket Receipts Attached is a copy or fax of the airline ticket receipt (last page of the ticket stub). - OR - I certify that I have contacted the agency and was unable to obtain a copy of the ticket receipt. Therefore I have attached one of the following: A copy of the GE Corporate Mastercard statement A copy of the itinerary invoice and form of payment (i.e., credit card statement, cancelled check) Hotel Folio Attached is a copy or fax of the hotel folio and proof of payment. - OR - I certify that I have contacted the hotel and was unable to obtain a copy of the hotel folio. Please reimburse me based on the following information and proof of payment: Dates Hotel/City # of Nights Daily Rate* Total *Daily rate excluding taxes and service charges. Car Rental Agreement Attached is a copy or fax of the car rental agreement and proof of payment. - OR - I certify that I have contacted the rental car agency and was unable to obtain a copy of the car rental agreement. Please reimburse me based on the following information and proof of payment: Dates Rental Company Car Class* # of Days Total # of People Total *C=Compact, M=Mid-size, F=Full-size Date B, L, D* Meals (list each meal separately) Restaurant/City *B=Breakfast, L=Lunch, D=Dinner (Note: if more than 1 person, please include business purpose on Expense Report or PCard Settlement System.) Miscellaneous Attached is a copy of the PCard statement. Date Description (in detail) Total I, the undersigned, certify (a) that each expense described above, reported on expense report number or PCard transaction number , dated was lost or not obtained, and (b) that these expenses have not yet nor will again be submitted to Harvard University or any other organization for reimbursement or tax purposes. Signature of Payee/Cardholder Date REQUIRED Authorized Signature Date REQUIRED DOCUMENTATION REQUIREMENTS The University requires individuals to submit the following documentation to substantiate all expenses in excess of $75. • • • • Air/Rail – original ticket receipt Hotel – hotel folio is required for all lodging expenses, regardless of cost. Car Rental – car rental agreement receipt Personal Car Usage – receipts for tolls and parking and daily mileage log listing date, itinerary, and number of miles • Meals/Entertainment – credit card receipt or cash register receipt (no restaurant tear tabs) • Receipts must include the name of the vendor, location, date, and dollar amount. • Detailed cash or sales receipts • Packing slips with a dollar amount • Subscription or dues forms Please Note: Some schools require receipts for all expenses. Transactions under $75 do not need receipts unless otherwise required by the individual school or because of conflict with funding agency requirements. Lodging transactions require hotel folio regardless of amount. MISSING RECEIPTS General Individuals must attempt to obtain a copy of the original receipt from the vendor for all travel costs in excess of $75. Missing receipt affidavits must be signed by both the individual and authorized signer with a complete explanation of the expense if a copy of the receipt is unobtainable. PCard Receipts Cardholders are required to obtain original receipts for all transactions in excess of $75. If this is not possible, a missing receipt affidavit must be completed and signed by the cardholder and the PCard administrator. Airline Ticket Receipt In the event of a missing airline receipt (last page of the ticket stub), the affidavit must be accompanied by some form of documentation. The agency issuing the original ticket must be contacted and a copy of the receipt requested. All agencies are required by the Airline Reporting Commission to keep copies of every ticket they issue. If the traveler is unable to obtain a copy of the airline receipt, acceptable alternatives are: A copy of the airline or agency itinerary showing form of payment, the corporate card statement or cancelled check. One must be included with the missing receipt affidavit. Hotel Folio The IRS requires a hotel folio or itemized bill for all lodging reimbursements. The $75 limit does not apply to lodging expenses. For complete information on expense reporting, please refer to the Harvard University Travel and Entertainment Policy and Reference Manual. From: To: Subject: Date: Mahoney, Jo-Ann Mahoney, Jo-Ann HEPG Logistics Monday, June 09, 2014 8:55:44 AM Dear Participants,   We look forward to seeing you this week at the Harvard Electricity Policy Group 75th Plenary session on Thursday-Friday, June 12-13.  Our agenda is attached.  The sessions will take place on the fifth floor of the HKS Taubman Building, adjacent to the Charles Hotel.  Full breakfast will be available at 8:30 each day and the meetings will convene at 9:00 am.     On Thursday evening, we will  travel to the Boston harbor for our conference reception and dinner.   Weather permitting, we will hold the reception outdoors, followed by dinner at Meritage Restaurant prepared by Chef Daniel Bruce, founder of the Boston Wine Festival.  Transportation to and from Cambridge will be provided, departing from the Charles Hotel at 6:15 pm.   All the best, Jo-Ann   Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group, Harvard Kennedy School (617) 495-1390     From: To: Cc: Subject: Date: Bob Stump Bostian, Trudi Beth L. Soliere Re: HEPG Dinner? Monday, June 02, 2014 11:09:40 AM Thanks, Trudi - I will be. If there's space for my mother, that would be great, as well.... Bob Sent from my iPhone On Jun 2, 2014, at 7:21 AM, "Bostian, Trudi" wrote: Hi Bob,   Please let me know if you’ll be joining us for dinner on June 12th?   Thank you.   ******************************* Trudi R. Bostian Staff Assistant Harvard Electricity Policy Group 79 John F. Kennedy Street Cambridge, MA 02138 P: 617-496-6760 E: trudi_bostian@hks.harvard.edu   From: To: Subject: Date: Beth L. Soliere Bob Stump FW: Invitation to HEPG Dinner, RSVP Friday, May 30, 2014 11:20:28 AM For the Boston trip.   From: Bostian, Trudi [mailto:Trudi_Bostian@hks.harvard.edu] Sent: Tuesday, May 27, 2014 7:53 AM Subject: Invitation to HEPG Dinner, RSVP   Dear HEPG Participants:   We will be holding the HEPG dinner on Thursday, June 12th.  You are welcome to bring a guest who is travelling with you, but we would like to know if you will be joining us.  Kindly RSVP, acceptances or regrets, by Thursday, May 29th.    ******************************* Trudi R. Bostian Staff Assistant Harvard Electricity Policy Group 79 John F. Kennedy Street Cambridge, MA 02138 P: 617-496-6760 E: trudi_bostian@hks.harvard.edu   From: To: Subject: Date: Attachments: Bob Stump Beth L. Soliere Fwd: FW: HEPG Agenda Friday, May 16, 2014 3:39:14 PM Draft_Agenda_June2014.docx Let's go ahead and print out and put in a folder.  thanks. ---------- Forwarded message ---------From: Beth L. Soliere Date: Thu, May 8, 2014 at 10:21 AM Subject: FW: HEPG Agenda To: Bob Stump Cc: Bob Stump     From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Thursday, May 08, 2014 9:40 AM To: Mahoney, Jo-Ann Subject: HEPG Agenda   We look forward to your participation in the upcoming plenary session of the Harvard Electricity Policy Group to be held on June 12-13 here at the Harvard Kennedy School, and are pleased to send you the agenda and list of speakers.    You most likely have seen Ashley Brown’s letter to the editor in  last Sunday’s New York Times and the Wall Street Journal editorial on market manipulation.  We include links to the articles for you here as well.   Best, Jo-Ann   Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group (HEPG) Harvard Kennedy School 79 JFK Street Cambridge, MA 02138 617-495-1390   From: Bostian, Trudi Sent: Wednesday, May 07, 2014 10:00 AM To: Mahoney, Jo-Ann Subject: Draft_Agenda_June2014.docx   Draft agenda.     ******************************* Trudi R. Bostian Staff Assistant Harvard Electricity Policy Group 79 John F. Kennedy Street Cambridge, MA 02138 P: 617-496-6760 E: trudi_bostian@hks.harvard.edu     ========================================== This footnote confirms that this email message has been scanned to detect malicious content. If you experience problems, please e-mail postmaster@azcc.gov ========================================== -Bob Stump Chair, Phoenix Opera 3120 West Carefree Highway, Suite 1-106 Phoenix, AZ 85086 Chair, Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 602?542?3935 HARVARD ELECTRICITY POLICY GROUP HARVARD ELECTRICITY POLICY GROUP SEVENTY-FIFTH PLENARY SESSION Harvard Kennedy School Cambridge, Massachusetts THURSDAY AND FRIDAY, JUNE 12-13, 2014 DRAFT AGENDA Thursday, June 12 8:30 am Breakfast and Informal Discussion 9:00 am Session One. Uplift Downside The simple model of electricity supply and demand utilizes locational market-clearing prices for load and generation. The model is silent on the treatment of overhead costs and other administrative payments. Traditionally these relatively small costs were relegated to market design fine print under the British label of “uplift” charges. Thought to be a minor inconvenience, the growth in uplift charges has been a source of increasing concern and controversy. What are the sources of costs that are part of the uplift? Why has the uplift category expanded? How do uplift costs support reliable economic dispatch? How much of uplift is necessary, and how much is a reflection of defects in market design? How do uplift cost allocations affect load, generation, virtual transactions and all the many steps in the electricity system? If retail consumers desire fixed rate contracts, how can retail aggregators face increasing uncertainty in uplift costs, which threatens the business model of these providers? Do increasing uplift costs create a risk that can threaten ongoing development of retail competition due to increased hedging and risk management costs? How does uplift affect the incentives and opportunities for market manipulation? How might uplift rules interact with price determination? How can we live with the necessity for some uplift and avoid the downside of uplift charges growing out of control? Moderator: William Hogan, Harvard Electricity Policy Group Stu Bresler, PJM Interconnection Gregory Lawrence, Cadwalader, Wickersham & Taft Jeffrey Levine, GDF Suez Harry Singh, Goldman Sachs PHONE 617-496-6760 FAX 617-495-1635 EMAIL HEPG@ksg.harvard.edu 79 John F. Kennedy Street, Box 84 Cambridge, Massachusetts 02138 www.hks.harvard.edu/hepg HEPG Draft Agenda, June 12-13, 2014 Thursday, June 12 (cont’d) 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Lunch 1:15 pm Session Two. Regulating Generation: When do Wholesale and Retail Generation Become Part of the Same Whole? The dramatic increase in the amount of distributed generation, the re-emergence of PURPA QF facilities with its associated calculation of avoided costs, the enactment of RPS standards in many states, and the creation of a demand response market, raise the fundamental question of whether the traditional distinctions between retail and wholesale markets are still valid. Are these two heretofore separate markets converging? If so, what are the legal, jurisdictional, and policy implications? If they are not full converging , how do we deal with the effects that one market has on the other. We have already seen recent disputes between state and federal regulators on PURPA requirements, on jurisdiction over demand side response, and even on renewable energy matters. Are these disputes harbingers of more debates to come and where are we headed in terms of both jurisdiction and of policy/market rules coherence? Kenneth Anderson, Public Utility Commission of Texas Travis Kavulla, Montana Public Service Commission Dave Raskin, Steptoe & Johnson Jan Smutny-Jones, Independent Energy Producers Association 2:45 pm Coffee Break 3:00 pm Discussion 4:15 pm Adjourn 6:30 pm Reception and Dinner HEPG Draft Agenda, June 12-13, 2014 Friday, June 13 8:30 am Breakfast and Informal Discussion 9:00 am Session Three. Cyber-Security vs. Physical Security/High Voltage vs. Low Voltage: Which Should Be the Priority? With growing demands for increased grid security, there is a growing tension between demands for greater physical security of network facilities and upgrades to protect against cyber-attacks. These demands must also be seen in the context that most service interruptions are experienced on the low voltage, distribution, systems that are highly vulnerable to environmental and other challenges, while the mega threats envisioned by national security advocates are at the system operations or high voltage, transmission levels, and/or at large generating facilities. While both levels merit concern, which should have priority for the industry and for regulators? What are the metrics for measuring the cost-effectiveness of investments in security? How should regulators respond to these competing demands in terms of cost allocation and recovery decisions from customer classes with differing needs for secure supply? What should be subject to government mandates and what should be left to the discretion of the industry? Tamara Linde, PSEG Services Corporation Venkatesh Narayanamurti, Harvard Kennedy School Steven Naumann, Exelon Corp. Catherine Sandoval, California Public Utilities Commission 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Adjourn From: To: Cc: Subject: Date: Attachments: Beth L. Soliere Bob Stump "Bob Stump" FW: HEPG Agenda Thursday, May 08, 2014 10:21:32 AM Draft_Agenda_June2014.docx     From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Thursday, May 08, 2014 9:40 AM To: Mahoney, Jo-Ann Subject: HEPG Agenda   We look forward to your participation in the upcoming plenary session of the Harvard Electricity Policy Group to be held on June 12-13 here at the Harvard Kennedy School, and are pleased to send you the agenda and list of speakers.    You most likely have seen Ashley Brown’s letter to the editor in  last Sunday’s New York Times and the Wall Street Journal editorial on market manipulation.  We include links to the articles for you here as well.   Best, Jo-Ann   Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group (HEPG) Harvard Kennedy School 79 JFK Street Cambridge, MA 02138 617-495-1390   From: Bostian, Trudi Sent: Wednesday, May 07, 2014 10:00 AM To: Mahoney, Jo-Ann Subject: Draft_Agenda_June2014.docx   Draft agenda.     ******************************* Trudi R. Bostian Staff Assistant Harvard Electricity Policy Group 79 John F. Kennedy Street Cambridge, MA 02138 P: 617-496-6760 E: trudi_bostian@hks.harvard.edu     HARVARD ELECTRICITY POLICY GROUP HARVARD ELECTRICITY POLICY GROUP SEVENTY-FIFTH PLENARY SESSION Harvard Kennedy School Cambridge, Massachusetts THURSDAY AND FRIDAY, JUNE 12-13, 2014 DRAFT AGENDA Thursday, June 12 8:30 am Breakfast and Informal Discussion 9:00 am Session One. Uplift Downside The simple model of electricity supply and demand utilizes locational market-clearing prices for load and generation. The model is silent on the treatment of overhead costs and other administrative payments. Traditionally these relatively small costs were relegated to market design fine print under the British label of “uplift” charges. Thought to be a minor inconvenience, the growth in uplift charges has been a source of increasing concern and controversy. What are the sources of costs that are part of the uplift? Why has the uplift category expanded? How do uplift costs support reliable economic dispatch? How much of uplift is necessary, and how much is a reflection of defects in market design? How do uplift cost allocations affect load, generation, virtual transactions and all the many steps in the electricity system? If retail consumers desire fixed rate contracts, how can retail aggregators face increasing uncertainty in uplift costs, which threatens the business model of these providers? Do increasing uplift costs create a risk that can threaten ongoing development of retail competition due to increased hedging and risk management costs? How does uplift affect the incentives and opportunities for market manipulation? How might uplift rules interact with price determination? How can we live with the necessity for some uplift and avoid the downside of uplift charges growing out of control? Moderator: William Hogan, Harvard Electricity Policy Group Stu Bresler, PJM Interconnection Gregory Lawrence, Cadwalader, Wickersham & Taft Jeffrey Levine, GDF Suez Harry Singh, Goldman Sachs PHONE 617-496-6760 FAX 617-495-1635 EMAIL HEPG@ksg.harvard.edu 79 John F. Kennedy Street, Box 84 Cambridge, Massachusetts 02138 www.hks.harvard.edu/hepg HEPG Draft Agenda, June 12-13, 2014 Thursday, June 12 (cont’d) 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Lunch 1:15 pm Session Two. Regulating Generation: When do Wholesale and Retail Generation Become Part of the Same Whole? The dramatic increase in the amount of distributed generation, the re-emergence of PURPA QF facilities with its associated calculation of avoided costs, the enactment of RPS standards in many states, and the creation of a demand response market, raise the fundamental question of whether the traditional distinctions between retail and wholesale markets are still valid. Are these two heretofore separate markets converging? If so, what are the legal, jurisdictional, and policy implications? If they are not full converging , how do we deal with the effects that one market has on the other. We have already seen recent disputes between state and federal regulators on PURPA requirements, on jurisdiction over demand side response, and even on renewable energy matters. Are these disputes harbingers of more debates to come and where are we headed in terms of both jurisdiction and of policy/market rules coherence? Kenneth Anderson, Public Utility Commission of Texas Travis Kavulla, Montana Public Service Commission Dave Raskin, Steptoe & Johnson Jan Smutny-Jones, Independent Energy Producers Association 2:45 pm Coffee Break 3:00 pm Discussion 4:15 pm Adjourn 6:30 pm Reception and Dinner HEPG Draft Agenda, June 12-13, 2014 Friday, June 13 8:30 am Breakfast and Informal Discussion 9:00 am Session Three. Cyber-Security vs. Physical Security/High Voltage vs. Low Voltage: Which Should Be the Priority? With growing demands for increased grid security, there is a growing tension between demands for greater physical security of network facilities and upgrades to protect against cyber-attacks. These demands must also be seen in the context that most service interruptions are experienced on the low voltage, distribution, systems that are highly vulnerable to environmental and other challenges, while the mega threats envisioned by national security advocates are at the system operations or high voltage, transmission levels, and/or at large generating facilities. While both levels merit concern, which should have priority for the industry and for regulators? What are the metrics for measuring the cost-effectiveness of investments in security? How should regulators respond to these competing demands in terms of cost allocation and recovery decisions from customer classes with differing needs for secure supply? What should be subject to government mandates and what should be left to the discretion of the industry? Tamara Linde, PSEG Services Corporation Venkatesh Narayanamurti, Harvard Kennedy School Steven Naumann, Exelon Corp. Catherine Sandoval, California Public Utilities Commission 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Adjourn From: To: Subject: Date: Bostian, Trudi Beth L. Soliere RE: HEPG 75th Plenary Session Thursday, May 01, 2014 6:53:46 AM Hi Beth,   Yes, we are working on this and will send you the confirmation number shortly.  Thanks.   ******************************* Trudi R. Bostian Staff Assistant Harvard Electricity Policy Group 79 John F. Kennedy Street Cambridge, MA 02138 P: 617-496-6760 E: trudi_bostian@hks.harvard.edu   From: Beth L. Soliere [mailto:BLSoliere@azcc.gov] Sent: Tuesday, April 29, 2014 2:55 PM To: Bostian, Trudi Subject: HEPG 75th Plenary Session   Hi Trudi,   Can I please reserve a room for Chairman Bob Stump for both June 11th and 12th?   Thank you,   Beth Soliere, Executive Aide Chairman Bob Stump Arizona Corporation Commission 1200 W. Washington Street Phoenix, AZ 85007 602-542-3935   ========================================== This footnote confirms that this email message has been scanned to detect malicious content. If you experience problems, please e-mail postmaster@azcc.gov ========================================== From: To: Subject: Date: Beth L. Soliere Amanda H. Ho FW: Invitation to HEPG 75th Plenary Session, June 12-13, 2014, Cambridge MA Tuesday, April 22, 2014 11:39:56 AM Amanda,   He wants to go to this forum in MA.  The 2nd day of OM would be the 11th which would be the day he should fly out.  Any idea on what that day will look like?   From: Bob Stump Sent: Tuesday, April 22, 2014 11:35 AM To: Beth L. Soliere Subject: Re: Invitation to HEPG 75th Plenary Session, June 12-13, 2014, Cambridge MA Hmmm. Maybe Amanda has a sense of what might be on second day of OM Sent from my iPhone On Apr 22, 2014, at 11:38 AM, "Beth L. Soliere" wrote: Do you want a room for both Wednesday and Thursday night? Departing on Friday?   From: Bob Stump Sent: Tuesday, April 15, 2014 9:09 AM To: Beth L. Soliere Subject: Fwd: Invitation to HEPG 75th Plenary Session, June 12-13, 2014, Cambridge MA Let's RSVP. Thanks. Sent from my iPhone Begin forwarded message: From: "Bostian, Trudi" Date: April 15, 2014 8:56:43 AM PDT To: Bob Stump , "Trisha A. Morgan" Subject: Invitation to HEPG 75th Plenary Session, June 12-13, 2014, Cambridge MA Dear Chairman Stump, The next meeting of the Harvard Electricity Policy Group will be held at the Harvard Kennedy School, 5th Floor of Taubman Building, in Cambridge on Thursday-Friday, June 12-13. We plan to discuss the convergence of wholesale and retail markets, cybersecurity and reliability issues, and a third topic to be announced. For your planning purposes, we will convene at 8:30 on Thursday and adjourn at noon on Friday; the market convergence panel will take place on Thursday afternoon and the cyber-security/reliability panel will be held on Friday morning (descriptions attached.) Our conference reception and dinner will take place on Thursday evening. As in the past, we are able to cover your travel expenses and can reserve you a room at the Harvard Faculty Club for Wednesday and/or Thursday nights. Please let me know by May 13 which nights you will need. Cambridge is extremely busy in June and hotel rooms are frequently hard to find, so please RSVP to me without delay to ensure that we can arrange suitable accommodations for you. Kindly return the conference registration form to us. We hope to see you in Cambridge in June. ******************************* Trudi R. Bostian Staff Assistant Harvard Electricity Policy Group 79 John F. Kennedy Street Cambridge, MA 02138 P: 617-496-6760 E: trudi_bostian@hks.harvard.edu REGULATING GENERATION : WHEN DO WHOLESALE AND RETAIL GNERATION BECOME PART OF THE SAME WHOLE? The dramatic increase in the amount of distributed generation, the reemergence of PURPA QF facilities with its associated calculation of avoided costs, the enactment of RPS standards in many states, and the creation of a demand response market, raise the fundamental question of whether the traditional distinctions between retail and wholesale market are still valid. Are these two heretofore separate markets converging. If so, what are the legal, jurisdictional, and policy implications? If they are not full converging , how do we deal with the effects that one market has on the other. We have already seen recent disputes between state and federal regulators on PURPA requirements, on jurisdiction over demand side response, and even on renewable energy matters. Are these disputes harbingers of more debates to come and where are we headed in terms of both jurisdiction and policy/market rules coherence?   CYBER-SECURITY VS. PHYSICAL SECURITY / HIGH VOLTAGE VS. LOW VOLTAGE: WHICH SHOULD BE THE PRIORITY? With growing demands for increased grid security, there is a growing tension between demands for greater physical security of network facilities and upgrades to protect against cyberattacks. These demands must also be seen in the context that most service interruptions are experienced on the low voltage, distribution systems that are highly vulnerable to environmental and other challenges, while the mega threats envisioned by national security advocates are at the system operations or high voltage, transmission levels, and/or at large generating facilities. While both levels merit concern, which should have priority for the industry and for regulators? What are the metrics for measuring the cost-effectiveness of investments in security? How should regulators respond to these competing demands in terms of cost allocation and recovery decisions from customer classes with differing needs for secure supply? What should be subject to government mandates and what should be left to the discretion of the industry? From: To: Subject: Date: Bob Stump Beth L. Soliere Re: Invitation to HEPG 75th Plenary Session, June 12-13, 2014, Cambridge MA Tuesday, April 22, 2014 11:36:21 AM Hmmm. Maybe Amanda has a sense of what might be on second day of OM Sent from my iPhone On Apr 22, 2014, at 11:38 AM, "Beth L. Soliere" wrote: Do you want a room for both Wednesday and Thursday night? Departing on Friday?   From: Bob Stump Sent: Tuesday, April 15, 2014 9:09 AM To: Beth L. Soliere Subject: Fwd: Invitation to HEPG 75th Plenary Session, June 12-13, 2014, Cambridge MA   Let's RSVP. Thanks.  Sent from my iPhone Begin forwarded message: From: "Bostian, Trudi" Date: April 15, 2014 8:56:43 AM PDT To: Bob Stump , "Trisha A. Morgan" Subject: Invitation to HEPG 75th Plenary Session, June 12-13, 2014, Cambridge MA Dear Chairman Stump,   The next meeting of the Harvard Electricity Policy Group will be held at the Harvard Kennedy School, 5th Floor of Taubman Building, in Cambridge on Thursday-Friday, June 12-13.   We plan to discuss the convergence of wholesale and retail markets, cybersecurity and reliability issues, and a third topic to be announced.  For your planning purposes, we will convene at 8:30 on Thursday and adjourn at noon on Friday; the market convergence panel will take place on Thursday afternoon and the cyber-security/reliability panel will be held on Friday morning (descriptions attached.) Our conference reception and dinner will take place on Thursday evening.      As in the past, we are able to cover your travel expenses and can reserve you a room at the Harvard Faculty Club for Wednesday and/or Thursday nights.  Please let me know by May 13 which nights you will need.  Cambridge is extremely busy in June and hotel rooms are frequently hard to find, so please RSVP to me without delay to ensure that we can arrange suitable accommodations for you.   Kindly return the conference registration form to us.   We hope to see you in Cambridge in June.   ******************************* Trudi R. Bostian Staff Assistant Harvard Electricity Policy Group 79 John F. Kennedy Street Cambridge, MA 02138 P: 617-496-6760 E: trudi_bostian@hks.harvard.edu   REGULATING GENERATION : WHEN DO WHOLESALE AND RETAIL GNERATION BECOME PART OF THE SAME WHOLE? The dramatic increase in the amount of distributed generation, the reemergence of PURPA QF facilities with its associated calculation of avoided costs, the enactment of RPS standards in many states, and the creation of a demand response market, raise the fundamental question of whether the traditional distinctions between retail and wholesale market are still valid. Are these two heretofore separate markets converging.  If so, what are the legal, jurisdictional, and policy implications? If they are not full converging , how do we deal with the effects that one market has on the other.  We have already seen recent disputes between state and federal regulators on PURPA requirements, on jurisdiction over demand side response, and even on renewable energy matters. Are these disputes harbingers of more debates to come and where are we headed in terms of both jurisdiction and policy/market rules coherence?   CYBER-SECURITY VS. PHYSICAL SECURITY / HIGH VOLTAGE VS. LOW VOLTAGE: WHICH SHOULD BE THE PRIORITY? With growing demands for increased grid security, there is a growing tension between demands for greater physical security of network facilities and upgrades to protect against cyberattacks.  These demands must also be seen in the context that most service interruptions are experienced on the low voltage, distribution systems that are highly vulnerable to environmental and other challenges, while the mega threats envisioned by national security advocates are at the system operations or high voltage, transmission levels, and/or at large generating facilities. While both levels merit concern, which should have priority for the industry and for regulators? What are the metrics for measuring the cost-effectiveness of investments in security? How should regulators respond to these competing demands in terms of cost allocation and recovery decisions from customer classes with differing needs for secure supply?  What should be subject to government mandates and what should be left to the discretion of the industry?       From: To: Subject: Date: Bob Stump Amanda H. Ho Fwd: Invitation to HEPG 75th Plenary Session, June 12-13, 2014, Cambridge MA Tuesday, April 15, 2014 4:43:31 PM I wonder if we can do OM all in one day, on the 10th.  Sent from my iPhone Begin forwarded message: From: "Bostian, Trudi" Date: April 15, 2014 8:56:43 AM PDT To: Bob Stump , "Trisha A. Morgan" Subject: Invitation to HEPG 75th Plenary Session, June 12-13, 2014, Cambridge MA Dear Chairman Stump,   The next meeting of the Harvard Electricity Policy Group will be held at the Harvard Kennedy School, 5th Floor of Taubman Building, in Cambridge on Thursday-Friday, June 12-13.   We plan to discuss the convergence of wholesale and retail markets, cybersecurity and reliability issues, and a third topic to be announced.  For your planning purposes, we will convene at 8:30 on Thursday and adjourn at noon on Friday; the market convergence panel will take place on Thursday afternoon and the cyber-security/reliability panel will be held on Friday morning (descriptions attached.) Our conference reception and dinner will take place on Thursday evening.      As in the past, we are able to cover your travel expenses and can reserve you a room at the Harvard Faculty Club for Wednesday and/or Thursday nights.  Please let me know by May 13 which nights you will need.  Cambridge is extremely busy in June and hotel rooms are frequently hard to find, so please RSVP to me without delay to ensure that we can arrange suitable accommodations for you.   Kindly return the conference registration form to us.   We hope to see you in Cambridge in June.   ******************************* Trudi R. Bostian Staff Assistant Harvard Electricity Policy Group 79 John F. Kennedy Street Cambridge, MA 02138 P: 617-496-6760 E: trudi_bostian@hks.harvard.edu   REGULATING GENERATION : WHEN DO WHOLESALE AND RETAIL GNERATION BECOME PART OF THE SAME WHOLE? The dramatic increase in the amount of distributed generation, the re-emergence of PURPA QF facilities with its associated calculation of avoided costs, the enactment of RPS standards in many states, and the creation of a demand response market, raise the fundamental question of whether the traditional distinctions between retail and wholesale market are still valid. Are these two heretofore separate markets converging.  If so, what are the legal, jurisdictional, and policy implications? If they are not full converging , how do we deal with the effects that one market has on the other.  We have already seen recent disputes between state and federal regulators on PURPA requirements, on jurisdiction over demand side response, and even on renewable energy matters. Are these disputes harbingers of more debates to come and where are we headed in terms of both jurisdiction and policy/market rules coherence?   CYBER-SECURITY VS. PHYSICAL SECURITY / HIGH VOLTAGE VS. LOW VOLTAGE: WHICH SHOULD BE THE PRIORITY? With growing demands for increased grid security, there is a growing tension between demands for greater physical security of network facilities and upgrades to protect against cyber-attacks.  These demands must also be seen in the context that most service interruptions are experienced on the low voltage, distribution systems that are highly vulnerable to environmental and other challenges, while the mega threats envisioned by national security advocates are at the system operations or high voltage, transmission levels, and/or at large generating facilities. While both levels merit concern, which should have priority for the industry and for regulators? What are the metrics for measuring the costeffectiveness of investments in security? How should regulators respond to these competing demands in terms of cost allocation and recovery decisions from customer classes with differing needs for secure supply?  What should be subject to government mandates and what should be left to the discretion of the industry?   From: To: Subject: Date: Attachments: Bob Stump Beth L. Soliere Fwd: Invitation to HEPG 75th Plenary Session, June 12-13, 2014, Cambridge MA Tuesday, April 15, 2014 9:09:02 AM Registration_form_6-14_comm.docx ATT00001..htm Let's RSVP. Thanks.  Sent from my iPhone Begin forwarded message: From: "Bostian, Trudi" Date: April 15, 2014 8:56:43 AM PDT To: Bob Stump , "Trisha A. Morgan" Subject: Invitation to HEPG 75th Plenary Session, June 12-13, 2014, Cambridge MA Dear Chairman Stump,   The next meeting of the Harvard Electricity Policy Group will be held at the Harvard Kennedy School, 5th Floor of Taubman Building, in Cambridge on Thursday-Friday, June 12-13.   We plan to discuss the convergence of wholesale and retail markets, cybersecurity and reliability issues, and a third topic to be announced.  For your planning purposes, we will convene at 8:30 on Thursday and adjourn at noon on Friday; the market convergence panel will take place on Thursday afternoon and the cyber-security/reliability panel will be held on Friday morning (descriptions attached.) Our conference reception and dinner will take place on Thursday evening.      As in the past, we are able to cover your travel expenses and can reserve you a room at the Harvard Faculty Club for Wednesday and/or Thursday nights.  Please let me know by May 13 which nights you will need.  Cambridge is extremely busy in June and hotel rooms are frequently hard to find, so please RSVP to me without delay to ensure that we can arrange suitable accommodations for you.   Kindly return the conference registration form to us.   We hope to see you in Cambridge in June.   ******************************* Trudi R. Bostian Staff Assistant Harvard Electricity Policy Group 79 John F. Kennedy Street Cambridge, MA 02138 P: 617-496-6760 E: trudi_bostian@hks.harvard.edu   REGULATING GENERATION : WHEN DO WHOLESALE AND RETAIL GNERATION BECOME PART OF THE SAME WHOLE? The dramatic increase in the amount of distributed generation, the re-emergence of PURPA QF facilities with its associated calculation of avoided costs, the enactment of RPS standards in many states, and the creation of a demand response market, raise the fundamental question of whether the traditional distinctions between retail and wholesale market are still valid. Are these two heretofore separate markets converging.  If so, what are the legal, jurisdictional, and policy implications? If they are not full converging , how do we deal with the effects that one market has on the other.  We have already seen recent disputes between state and federal regulators on PURPA requirements, on jurisdiction over demand side response, and even on renewable energy matters. Are these disputes harbingers of more debates to come and where are we headed in terms of both jurisdiction and policy/market rules coherence?   CYBER-SECURITY VS. PHYSICAL SECURITY / HIGH VOLTAGE VS. LOW VOLTAGE: WHICH SHOULD BE THE PRIORITY? With growing demands for increased grid security, there is a growing tension between demands for greater physical security of network facilities and upgrades to protect against cyber-attacks.  These demands must also be seen in the context that most service interruptions are experienced on the low voltage, distribution systems that are highly vulnerable to environmental and other challenges, while the mega threats envisioned by national security advocates are at the system operations or high voltage, transmission levels, and/or at large generating facilities. While both levels merit concern, which should have priority for the industry and for regulators? What are the metrics for measuring the costeffectiveness of investments in security? How should regulators respond to these competing demands in terms of cost allocation and recovery decisions from customer classes with differing needs for secure supply?  What should be subject to government mandates and what should be left to the discretion of the industry? REGISTRATION FORM HEPG SEVENTY-FIFTH PLENARY SESSION THURSDAY AND FRIDAY, JUNE 12-13, 2014 THE HARVARD KENNEDY SCHOOL CAMBRIDGE, MASSACHUSETTS TO: HARVARD ELECTRICITY POLICY GROUP John F. Kennedy School of Government FROM: Name Title Affiliation Address Phone E-mail ______YES, I will be able to attend the HEPG Plenary Session. ______ NO, I will not be able to attend the meeting. ______ I would like to send my designee: Name Title Address Phone E-mail ___________________________ ___________________________ ___________________________ ___________________________ ___________________________ ___________________________ HOTEL INFORMATION The conference will take place at the Harvard Kennedy School in Cambridge, MA. We have reserved a block of rooms at the Harvard Faculty Club, which is located at 20 Quincy Street in Cambridge, MA, and is accessible from Logan airport by taxi or subway. We can cover lodging for Wednesday and Thursday evening. To make your reservation, please contact Trudi Bostian (Trudi_bostian@hks.harvard.edu) and indicate which nights you need. To register for the session, please fax or e-mail this reply form to: Jo-Ann Mahoney, HEPG Program Director Fax: (617) 495-1635 Phone: (617) 495-1390 email to: jo-ann_mahoney@harvard.edu From: To: Subject: Date: Attachments: Bostian, Trudi Bob Stump; Trisha A. Morgan Invitation to HEPG 75th Plenary Session, June 12-13, 2014, Cambridge MA Tuesday, April 15, 2014 8:57:21 AM Registration_form_6-14_comm.docx Dear Chairman Stump,   The next meeting of the Harvard Electricity Policy Group will be held at the Harvard Kennedy School, 5th Floor of Taubman Building, in Cambridge on Thursday-Friday, June 12-13.   We plan to discuss the convergence of wholesale and retail markets, cybersecurity and reliability issues, and a third topic to be announced.  For your planning purposes, we will convene at 8:30 on Thursday and adjourn at noon on Friday; the market convergence panel will take place on Thursday afternoon and the cyber-security/reliability panel will be held on Friday morning (descriptions attached.) Our conference reception and dinner will take place on Thursday evening.      As in the past, we are able to cover your travel expenses and can reserve you a room at the Harvard Faculty Club for Wednesday and/or Thursday nights.  Please let me know by May 13 which nights you will need.  Cambridge is extremely busy in June and hotel rooms are frequently hard to find, so please RSVP to me without delay to ensure that we can arrange suitable accommodations for you.   Kindly return the conference registration form to us.   We hope to see you in Cambridge in June.   ******************************* Trudi R. Bostian Staff Assistant Harvard Electricity Policy Group 79 John F. Kennedy Street Cambridge, MA 02138 P: 617-496-6760 E: trudi_bostian@hks.harvard.edu   REGULATING GENERATION : WHEN DO WHOLESALE AND RETAIL GNERATION BECOME PART OF THE SAME WHOLE? The dramatic increase in the amount of distributed generation, the re-emergence of PURPA QF facilities with its associated calculation of avoided costs, the enactment of RPS standards in many states, and the creation of a demand response market, raise the fundamental question of whether the traditional distinctions between retail and wholesale market are still valid. Are these two heretofore separate markets converging.  If so, what are the legal, jurisdictional, and policy implications? If they are not full converging , how do we deal with the effects that one market has on the other.  We have already seen recent disputes between state and federal regulators on PURPA requirements, on jurisdiction over demand side response, and even on renewable energy matters. Are these disputes harbingers of more debates to come and where are we headed in terms of both jurisdiction and policy/market rules coherence?   CYBER-SECURITY VS. PHYSICAL SECURITY / HIGH VOLTAGE VS. LOW VOLTAGE: WHICH SHOULD BE THE PRIORITY? With growing demands for increased grid security, there is a growing tension between demands for greater physical security of network facilities and upgrades to protect against cyber-attacks.  These demands must also be seen in the context that most service interruptions are experienced on the low voltage, distribution systems that are highly vulnerable to environmental and other challenges, while the mega threats envisioned by national security advocates are at the system operations or high voltage, transmission levels, and/or at large generating facilities. While both levels merit concern, which should have priority for the industry and for regulators? What are the metrics for measuring the cost-effectiveness of investments in security? How should regulators respond to these competing demands in terms of cost allocation and recovery decisions from customer classes with differing needs for secure supply?  What should be subject to government mandates and what should be left to the discretion of the industry?       REGISTRATION FORM HEPG SEVENTY-FIFTH PLENARY SESSION THURSDAY AND FRIDAY, JUNE 12-13, 2014 THE HARVARD KENNEDY SCHOOL CAMBRIDGE, MASSACHUSETTS TO: HARVARD ELECTRICITY POLICY GROUP John F. Kennedy School of Government FROM: Name Title Affiliation Address Phone E-mail ______YES, I will be able to attend the HEPG Plenary Session. ______ NO, I will not be able to attend the meeting. ______ I would like to send my designee: Name Title Address Phone E-mail ___________________________ ___________________________ ___________________________ ___________________________ ___________________________ ___________________________ HOTEL INFORMATION The conference will take place at the Harvard Kennedy School in Cambridge, MA. We have reserved a block of rooms at the Harvard Faculty Club, which is located at 20 Quincy Street in Cambridge, MA, and is accessible from Logan airport by taxi or subway. We can cover lodging for Wednesday and Thursday evening. To make your reservation, please contact Trudi Bostian (Trudi_bostian@hks.harvard.edu) and indicate which nights you need. To register for the session, please fax or e-mail this reply form to: Jo-Ann Mahoney, HEPG Program Director Fax: (617) 495-1635 Phone: (617) 495-1390 email to: jo-ann_mahoney@harvard.edu From: To: Subject: Date: Trisha A. Morgan Bob Stump RE: Orlando hotel Friday, March 21, 2014 1:10:07 PM Yes, the hotel did put it on our travel card and it has paid by the business office.   From: Bob Stump Sent: Friday, March 21, 2014 12:39 PM To: Trisha A. Morgan Subject: Orlando hotel   I don’t see any charges for the Orlando Hotel anywhere – must have been put on the business credit card?   THANKS…   From: Trisha A. Morgan Sent: Friday, March 21, 2014 11:01 AM To: Bob Stump Subject: RE: October NARUC?   Attended HEPG Sept. 24-27, 2013 and then traveled to Nova Scotia, returned to Phoenix Monday, October 7th.    Next conference was NARUC November 17-20, 2013 in Florida.   From: Bob Stump Sent: Friday, March 21, 2014 10:51 AM To: Trisha A. Morgan Subject: October NARUC?   I see I was at some NARUC meeting in early October…recall what that was?  Thanks…   From: To: Subject: Date: Trisha A. Morgan Bob Stump RE: October NARUC? Friday, March 21, 2014 11:00:40 AM Attended HEPG Sept. 24-27, 2013 and then traveled to Nova Scotia, returned to Phoenix Monday, October 7th.    Next conference was NARUC November 17-20, 2013 in Florida.   From: Bob Stump Sent: Friday, March 21, 2014 10:51 AM To: Trisha A. Morgan Subject: October NARUC?   I see I was at some NARUC meeting in early October…recall what that was?  Thanks…   From: To: Subject: Date: Attachments: Bostian, Trudi kenneth.anderson@puc.texas.gov; Monica.Lambert@puc.texas.gov; Rich.Wakeland@puc.texas.gov; Susan Bitter Smith; Teresa Tenbrink; rborlick@borlick.com; mike.florio@cpuc.ca.gov; joan.dahlgren@cpuc.ca.gov; mf1@cpuc.ca.gov; jeanne.fox@bpu.state.nj.us; deborah.laird@bpu.state.nj.us; r.csira@bpu.state.nj.us; jfreeman@pa.gov; amccabe@icc.illinois.gov; cweller@icc.illinois.gov; donna.nelson@puc.texas.gov; Lisa.Cantu@puc.texas.gov; richard.oneill@ferc.gov; bethann.ross@ferc.gov; catherine.sandoval@cpuc.ca.gov; dscott@icc.illinois.gov; cweller@icc.illinois.gov; Bob Stump; Trisha A. Morgan Reimbursements for last week"s HEPG Wednesday, March 05, 2014 8:07:27 AM w-9.pdf missing_receipt.pdf universal_expense_form.pdf Hello,   I hope you enjoyed last week’s session of the Harvard Electricity Policy Group.    Harvard is happy to reimburse your travel and travel related expenses, including taxis, meals en route, baggage fees, and parking fees.  If you have additional expenses of which you are unsure, please don’t hesitate to ask.   There are two methods of reimbursement, depending on whether or not we are reimbursing you as an individual, or reimbursing your organization.  In both cases, I will need all receipts, originals preferred; if you are missing any receipts, you can use the attached missing receipt affidavit form.   If we are reimbursing your organization: Please send me an invoice, which should be a letter on official stationery, with all charges itemized, and including where and to whom payment should be sent.   If we are reimbursing you personally: Please fill out the attached Universal Expense Form.  Be sure to include your Social Security Number, the address where you want the check mailed, and your signature.   If you are new to our system, I’ll also need a signed W9 form.   ******************************* Trudi R. Bostian Staff Assistant Harvard Electricity Policy Group 79 John F. Kennedy Street Cambridge, MA 02138 P: 617-496-6760 E: trudi_bostian@hks.harvard.edu   Form W'g (Rev. December 2011) Department of the Treasury Internal Revenue Service Name (as shown on your income tax return) PRESIDENT AND FELLOWS OF HARVARD COLLEGE Business name/disregarded entity name. if different from above Harvard University RequestforTaxpayer Identification Number and Certification Give Form to the requester. Do not send to the IRS. Check appropriate box for federal tax classification: El Individual/sole proprietor Cl Corporation Print or type Other (see instructions) El Corporation El Partnership CI Trust/estate El Limited liability company. Enter the tax classification corporation, corporation, P=partnership) 501 (CH3) President and Fellows of Harvard Coliege Exempt payee Address (number, street, and apt. or suite no.) 1033 Massachusetts Ave, 2nd Floor Requester's name and address (optional) City, state, and ZIP code Cambridge, MA 02138 See Specific Instructions on page 2. List account number(s) here (optional) Taxpayer Identification Number (TIN) Enter your TIN in the appropriate box. The TIN provided must match the name given on the ?Name" line to avoid backup withholding. For individuals, this is your social security number (SSN). However, for a resident alien, sole proprietor, or disregarded entity, see the Part instructions on page 3. For other - - entities, it is your employer identification number (EIN). If you do not have a numberpage 3. Note. If the account is in more than one name, see the chart on page 4 for guidelines on whose number to enter. Part II Certification Under penalties of perjury, i certify that: Social security number Employer identification number 1. The number shown on this form is my correct taxpayer identification number (or I am waiting for a number to be issued to me), and 2. I am not subject to backup withholding because: I am exempt from backup withholding, or I have not been notified by the Internal Revenue Service that I am subject to backup withholding as a result of a failure to report all interest or dividends, or the IRS has notified me that I am no longer subject to backup withholding, and 3. i am a US. citizen or other US. person (defined below). Certification instructions. You must cross out item 2 above if you have been notified by the IRS that you are currently subject to backup withholding because you have failed to report all interest and dividends on your tax return. For real estate transactions, item 2 does not apply. For mortgage interest paid, acquisition or abandonment of secured property, cancellation of debt, contributions to an individual retirement arrangement (IRA), and generally, payments other than interest and dividends, you are not required to sign the certification, but you must provide your correct TIN. See the instructions on page 4. 3'9" Signature of Here US. person General Instructions Section references are to the Internal Revenue Code unless othenrvise noted. Purpose of Form A person who is required to file an information return with the IRS must obtain your correct taxpayer identification number (TIN) to report, for example, income paid to you, rest estate transactions, mortgage interest you paid, acquisition or abandonment of secured property, cancellation of debt, or contributions you made to an IRA. Use Form only if you are a US. person (including a resident alien), to provide your correct TIN to the person requesting it (the requester) and, when applicable, to: 1. Certify that the TIN you are giving is correct (or you are waiting for a number to be issued), 2. Certify that you are not subject to backup withholding, or 3. Claim exemption from backup withholding if you are a U.S.-exempt payee. If applicable, you are also certifying that as a US. person, your allocable share of any partnership income from a US. trade or business is not subject to the withholding tax on foreign partners? share of effectively connected income. Cat. No. 10231X Tit, (WW QWM Date} 02-/ 010 13 Note. if a requester gives you a form other than Form to request your TIN, you must use the requester?s form if it is substantially simiiar to this Form W-9. Definition of a U.S. person. For federal tax purposes, you are considered a US. person if you are: An individual who is a U.S. citizen or U.S. resident alien, A partnership, corporation, company, or association created or organized in the United States or under the laws of the United States, 0 An estate (other than a foreign estate), or 0 A domestic trust (as defined in Regulations section 301 .7701-7). Special rules for partnerships. Partnerships that conduct a trade or business in the United States are generally required to pay a withholding tax on any foreign partners' share of income from such business. Further, in certain cases where a Form W-9 has not been received, a partnership is required to presume that a partner is a foreign person, and pay the withhoiding tax. Therefore, if you are a U.S. person that is a partner in a partnership conducting a trade or business in the United States, provide Form to the partnership to establish your U.S. status and avoid withholding on your share of partnership income. Form W-9 (Rev. 12-201 1) pcard, mra, lost, forgot, print, form, documentation, required HARVARD UNIVERSITY MISSING RECEIPT AFFIDAVIT Please read the Missing Receipt Affidavit requirements on the back of this form. Missing Receipt Affidavits lacking the required information or documentation will be returned to the authorized signer. Airline Ticket Receipts Attached is a copy or fax of the airline ticket receipt (last page of the ticket stub). - OR - I certify that I have contacted the agency and was unable to obtain a copy of the ticket receipt. Therefore I have attached one of the following: A copy of the GE Corporate Mastercard statement A copy of the itinerary invoice and form of payment (i.e., credit card statement, cancelled check) Hotel Folio Attached is a copy or fax of the hotel folio and proof of payment. - OR - I certify that I have contacted the hotel and was unable to obtain a copy of the hotel folio. Please reimburse me based on the following information and proof of payment: Dates Hotel/City # of Nights Daily Rate* Total *Daily rate excluding taxes and service charges. Car Rental Agreement Attached is a copy or fax of the car rental agreement and proof of payment. - OR - I certify that I have contacted the rental car agency and was unable to obtain a copy of the car rental agreement. Please reimburse me based on the following information and proof of payment: Dates Rental Company Car Class* # of Days Total # of People Total *C=Compact, M=Mid-size, F=Full-size Date B, L, D* Meals (list each meal separately) Restaurant/City *B=Breakfast, L=Lunch, D=Dinner (Note: if more than 1 person, please include business purpose on Expense Report or PCard Settlement System.) Miscellaneous Attached is a copy of the PCard statement. Date Description (in detail) Total I, the undersigned, certify (a) that each expense described above, reported on expense report number or PCard transaction number , dated was lost or not obtained, and (b) that these expenses have not yet nor will again be submitted to Harvard University or any other organization for reimbursement or tax purposes. Signature of Payee/Cardholder Date REQUIRED Authorized Signature Date REQUIRED DOCUMENTATION REQUIREMENTS The University requires individuals to submit the following documentation to substantiate all expenses in excess of $75. • • • • Air/Rail – original ticket receipt Hotel – hotel folio is required for all lodging expenses, regardless of cost. Car Rental – car rental agreement receipt Personal Car Usage – receipts for tolls and parking and daily mileage log listing date, itinerary, and number of miles • Meals/Entertainment – credit card receipt or cash register receipt (no restaurant tear tabs) • Receipts must include the name of the vendor, location, date, and dollar amount. • Detailed cash or sales receipts • Packing slips with a dollar amount • Subscription or dues forms Please Note: Some schools require receipts for all expenses. Transactions under $75 do not need receipts unless otherwise required by the individual school or because of conflict with funding agency requirements. Lodging transactions require hotel folio regardless of amount. MISSING RECEIPTS General Individuals must attempt to obtain a copy of the original receipt from the vendor for all travel costs in excess of $75. Missing receipt affidavits must be signed by both the individual and authorized signer with a complete explanation of the expense if a copy of the receipt is unobtainable. PCard Receipts Cardholders are required to obtain original receipts for all transactions in excess of $75. If this is not possible, a missing receipt affidavit must be completed and signed by the cardholder and the PCard administrator. Airline Ticket Receipt In the event of a missing airline receipt (last page of the ticket stub), the affidavit must be accompanied by some form of documentation. The agency issuing the original ticket must be contacted and a copy of the receipt requested. All agencies are required by the Airline Reporting Commission to keep copies of every ticket they issue. If the traveler is unable to obtain a copy of the airline receipt, acceptable alternatives are: A copy of the airline or agency itinerary showing form of payment, the corporate card statement or cancelled check. One must be included with the missing receipt affidavit. Hotel Folio The IRS requires a hotel folio or itemized bill for all lodging reimbursements. The $75 limit does not apply to lodging expenses. For complete information on expense reporting, please refer to the Harvard University Travel and Entertainment Policy and Reference Manual. HARVARD UNIVERSITY UNIVERSAL EXPENSE FORM EMPLOYEE TYPE OR AFFILIATION ❏ ❏ ❏ PAYMENT TYPE (CHECK ONLY ONE) Affiliate/Harvard Student/Casual/Stipend - complete shaded areas ❏ Out of Pocket ❏ American Express Corporate Card Invited Guest/Visitor - complete shaded areas Reimbursement Method (Check only one) Harvard Employee ❏ Direct Deposit ❏ Paper Check Date: Reimbursee or Cardholder Name: Social Sec/Tax ID#: Harvard ID#: Web Voucher/PO#: US Citizen or Permanent Resident: _______Yes _______ No Permanent Residents - Resident Alien Card # _____________ If you are not a US Citizen or Permanent Resident, provide: Visa Type: Country of Tax Residency: BUSINESS PURPOSE (Detailed reason for expenditure. For travel or entertainment, include person and/or organization visited and location. Also include expense date range. List additional business purposes on page 2.) Date(s) of expense(s) #1 #2 #3 #4 #5 SUMMARY OF EXPENSES (Room for additional expenses is available on page 2) Business Purpose# Description (date, detail, etc…) Air/Rail Travel Ground Trans. Lodging Business Meals Other Total Subtotals from page 2, if applicable: LESS ADVANCES EXPENSE REPORT TOTAL: TOTAL AMOUNT OF RECEIPTS UNDER $75 $ $ $ REIMBURSEE: I certify that these are all legitimate Harvard University business expenses. SIGNATURE: Date: Reimbursee Permanent Legal Address: Reimbursee Check Mailing Address, if different than Legal: I have reviewed these expenses and all are in accordance with University and Tub policy. Preparer: __________________________________ Phone: ___________ Approver: ___________________________________ 1 (PRINT) (SIGNATURE) HARVARD UNIVERSITY UNIVERSAL EXPENSE FORM – SUPPLEMENTAL INFORMATION PAGE ____OF ___ Reimbursee or Cardholder Name: Web Voucher/PO#: Departmental Accounting The area below is for departments whose financial office requires this information for processing purposes. This information will be captured in the Web Voucher System. Business Purpose# Amount Tub (3) Org (5) Object (4) Fund (6) Activity (6) Sub (4) Root (5) $ ADDITIONAL BUSINESS PURPOSES OR INFORMATION Date(s) of expense(s) #6 #7 #8 #9 ADDITIONAL EXPENSES Business Purpose# Description (date, detail, etc.) Air/Rail Travel Ground Trans Lodging Business Meals Other Total Subtotals, carry to first sheet Hints and policy notes: 1. 2. 3. 2 You may attach an AMEX statement in lieu of completing the description section. Cross-reference business purpose to each item on the statement by writing the business purpose # next to the itemized lines. Please refer to the Policy at a Glance or the complete travel policy at www.travel.harvard.edu. To expedite processing, contact the Travel Office at 495-7760 with policy questions prior to submitting this form. From: To: Subject: Date: Bostian, Trudi Bob Stump; Trisha A. Morgan HEPG Hotel confirmation Thursday, February 20, 2014 10:05:31 AM Hello,   Your hotel confirmation number at Shutters on the Beach is 15092814.   ******************************* Trudi R. Bostian Staff Assistant Harvard Electricity Policy Group 79 John F. Kennedy Street Cambridge, MA 02138 P: 617-496-6760 E: trudi_bostian@hks.harvard.edu   From: To: Subject: Date: Trisha A. Morgan Bob Stump RE: URGENT - Please RSVP to HEPG Dinner next Thursday, Feb 27 Thursday, February 20, 2014 8:36:24 AM Even though you did RSVP for the meeting, I went ahead and sent in their registration form so a room could be reserved for you.  Also let them know you will be attending the dinner.  I bet the weather will be terrific in California next week.  Also, let Jo Ann know you would be arriving Wednesday, February 26th, and returning to Phoenix on Friday, February 28th.  You have the Heritage Award Dinner to attend.    Still fighting the sinus problems but doing better each day.  It is like an early Spring here in Arizona!  Trees/flowers blooming earlier than usual.   Take care, Trisha   From: Bob Stump Sent: Thursday, February 20, 2014 8:06 AM To: Bostian, Trudi Cc: Trisha A. Morgan Subject: Re: URGENT - Please RSVP to HEPG Dinner next Thursday, Feb 27 Thanks, Trudi - I am. Bob Sent from my iPhone On Feb 20, 2014, at 10:03 AM, "Bostian, Trudi" wrote: Hello, I will need to know by COB today if you are planning to join us for dinner next week. Thank you. The conference reception and dinner will take place on Thursday evening at Melisse restaurant. Chef Josiah Citrin will once again be preparing a special meal for us. If you are travelling with a spouse or guest, you are most welcome to bring her or him to the event. Kindly RSVP for the reception and dinner to trudi_bostian@hks.harvard.edu. Transportation to Melisse, in downtown Santa Monica, will be provided. ******************************* Trudi R. Bostian Staff Assistant Harvard Electricity Policy Group 79 John F. Kennedy Street Cambridge, MA 02138 P: 617-496-6760 E: trudi_bostian@hks.harvard.edu From: Subject: Date: Importance: Bostian, Trudi URGENT - Please RSVP to HEPG Dinner next Thursday, Feb 27 Thursday, February 20, 2014 8:03:04 AM High Hello,   I will need to know by COB today if you are planning to join us for dinner next week.  Thank you.   The conference reception and dinner will take place on Thursday evening at Melisse restaurant.  Chef Josiah Citrin will once again be preparing a special meal for us.  If you are travelling with a spouse or guest, you are most welcome to bring her or him to the event.  Kindly RSVP for the reception and dinner to trudi_bostian@hks.harvard.edu. Transportation to Melisse, in downtown Santa Monica, will be provided.   ******************************* Trudi R. Bostian Staff Assistant Harvard Electricity Policy Group 79 John F. Kennedy Street Cambridge, MA 02138 P: 617-496-6760 E: trudi_bostian@hks.harvard.edu   From: To: Cc: Subject: Date: Attachments: Mahoney, Jo-Ann Mahoney, Jo-Ann Bostian, Trudi HEPG Santa Monica Meeting Logistics Thursday, February 06, 2014 9:40:15 AM DraftAgenda_Feb 2014.pdf We look forward to your participation in the next meeting of the Harvard Electricity Policy Group to be held in Santa Monica, California on Thursday-Friday, February 27-28.  The meeting will take place at Shutters on the Beach, located at One Pico Boulevard, Santa Monica.  Our agenda is attached.  Dress for the California session will be business casual.   The conference reception and dinner will take place on Thursday evening at Melisse restaurant.  Chef Josiah Citrin will once again be preparing a special meal for us.  If you are travelling with a spouse or guest, you are most welcome to bring her or him to the event.  Kindly RSVP for the reception and dinner to trudi_bostian@hks.harvard.edu. Transportation to Melisse, in downtown Santa Monica, will be provided.   All the best, Jo-Ann   Jo-Ann Mahoney Program Director Harvard Electricity Policy Group www. hks.harvard.edu/hepg Mossavar-Rahmani Center for Business & Government  Harvard Kennedy School 79 JFK St Cambridge MA 02138 jo-ann_mahoney@hks.harvard.edu Tel 617-495-1390  Fax 617.495-1635     HARVARD ELECTRICITY POLICY GROUP HARVARD ELECTRICITY POLICY GROUP SEVENTY-FOURTH PLENARY SESSION Shutters on the Beach Santa Monica, California THURSDAY AND FRIDAY, FEBRUARY 27-28, 2014 DRAFT AGENDA Thursday, February 27 8:30 am Breakfast and Informal Discussion 9:00 am Session One. Energy and Capacity Markets: Carts and Horses in Parallel Universes Turmoil in energy markets prompts action to redesign real-time pricing models for energy, scarcity, intermittency and uncertainty. The implications for revenue adequacy and investment in the right kind of capacity for generation and demand response yield a parallel universe of attempts to design better forward capacity markets. The parallel policy discussions struggle to deal with problems better treated if the universes were better connected. What are the major design defects in dayahead and real-time energy markets that give rise to the call for capacity markets? How can energy market redesign alter the need for and structure of capacity markets? What are the purposes that the capacity market would serve with a better energy market design? How can demand bidding, scarcity pricing, and better models of the value of reliability address the underlying problems, and simplify or improve the specification of what is needed for capacity markets? There is no alternative to having an energy market, and the principle of keeping the cart before the horse dictates the priority for fixing the energy markets. But most of the pressure is to fix old or found new capacity markets. Are there alternatives to capacity markets, and how can we think about the value that capacity markets bring to the electricity system? Moderator: Caroline Choi, Southern California Edison Dan Dolan, NEPGA William Hogan, Harvard Electricity Policy Group Richard O’Neill, FERC Johannes Pfeifenberger, The Brattle Group PHONE 617-496-6760 FAX 617-495-1635 EMAIL HEPG@ksg.harvard.edu 79 John F. Kennedy Street, Box 84 Cambridge, Massachusetts 02138 www.hks.harvard.edu/hepg HEPG Agenda, February 27-28, 2014 Thursday, February 27 (cont’d) 10:30 am Coffee Break 10:45 am Discussion 12:00 pm Lunch 1:15 pm Session Two. Transmission Planning: The Challenges Ahead Order 1000 provides some guidelines on how we should proceed with transmission planning, but the devil is surely in the details. How are we to make certain that the process is fully participatory without becoming so process-laden that effective decisions will be foreclosed? With the end of the right of first refusal (absent judicial intervention), how will it be determined who will build new facilities when no one has offered to fill a recognized void or where multiple parties are competing to serve the need? In fact, will transmission planners have to avail themselves of competitive mechanisms in order to ascertain what options should be pursued? How will we deal with all of the planning issues that arise from the increasing presence of intermittent, and often off-peak, resources on the grid? How will non-transmission line enhancements to the grid, such as strategic locating of generators, demand response, increased use of DG, and altered dispatching or dispatch protocols, be factored in? How might planning lead to fewer deviations from merit order dispatch? How different will the planning processes be in the various RTO market areas, and perhaps, even more interestingly, in non-RTO market areas? How will those differences affect seams issues? EPA regulations and the retirement of coal plants create short-term (in terms of transmission planning) uncertainties – which plants will retire and what transmission will be needed to meet reliability requirements? Shale gas is creating uncertainties in the resource mix going forward and in the definition of a contingency plan – what if your largest transmission contingency is on the gas system, not the electric system? How much coordination should transmission planners have with natural gas pipelines, and how should that be carried out? These are but a few of the issues that call out for clarity and resolution as we flush out the details of the new regime for planning the grid. Moderator: Ann McCabe, Illinois Commerce Commission Judy Chang, The Brattle Group Flora Flygt, American Transmission Company Rana Mukerji, New York ISO Mary Ellen Paravalos, National Grid 2:45 pm Coffee Break 3:00 pm Discussion 4:15 pm Adjourn 7:00 pm Reception and Dinner Mélisse, 1104 Wilshire Boulevard Transportation provided HEPG Agenda, February 27-28, 2014 Friday, February 28 8:30 am Breakfast and Informal Discussion 9:00 am Session Three. Distributed Generation: Alternative Ways of Pricing the Output and Dealing with the "Lost Revenue" and Cross-Subsidy Issues Distributed Generation (DG) in most U.S. jurisdictions, historically, was a marginal issue that was largely addressed by the simple, straightforward method of net metering. DG owners would pay nothing to the utility when they were consuming their own output and would be credited at the full retail price for any excess they exported to the system. While one could argue the merits of the methodology, the small volumes were insignificant. With the increased demand for renewables, largely motivated by carbon concerns, and the rise of a large scale DG solar industry substantially stimulated by subsidies like net metering, the issues associated with DG are no longer marginal. While the solar industry and many environmentalists are largely satisfied with the status quo, utilities are complaining about revenues needed to support the distribution network being diluted, low income groups are unhappy with what they see as a shift of costs to them from higher income consumers, many economists are concerned about “out of market” pricing, and utility scale generators complain about discriminatory pricing that puts them at a commercial disadvantage. The increasingly widespread use of smart meters enables that debate to be far richer than might have been possible just a few years ago. Among the alternatives are feed-in tariffs of various sorts, reallocating distribution costs with more emphasis on fixed rather than variable costs, paying the LMP for excess generation being exported into the system, charging DG customers for all the energy being consumed and then crediting them for what they self-generate (at LMP or some other level), and utilizing auctions of various sorts to set a market driven price. As the debate over how to deal with DG heats up, what methodologies ought to be on the table for serious consideration and implementation? Moderator: Cari Boyce, Duke Energy Ashley Brown, Harvard Electricity Policy Group Robert Borlick, Borlick Associates Michel Florio, California Public Utilities Commission Thomas Starrs, SunPower Corporation 10:45 am Coffee Break 11:00 am Discussion 12:00 pm Adjourn From: To: Subject: Date: Attachments: Bostian, Trudi Bob Stump; Trisha A. Morgan Invitation to the Harvard Electricity Policy Group 74th Plenary Session, Feb 27-28, 2014 Wednesday, January 22, 2014 8:50:38 AM Registration_form_2-14_comm.docx Dear Chairman Stump,   Our next session of the Harvard Electricity Policy Group will be held at Shutters on the Beach in Santa Monica, California on Thursday-Friday, February 27-28, 2014.  We plan to focus our panel discussions on:  transmission planning; pricing of distributed generation; and capacity market issues.  We will distribute panel descriptions and an agenda next week.  The meeting will convene at 9:00 am on Thursday and adjourn at noon on Friday, and there will be a conference dinner on Thursday evening in Santa Monica.    The reservation deadline for the HEPG block at Shutters on the Beach is January 28.  We are happy to book your hotel, so please let me know before the deadline which nights you would like.  We are also willing to cover your travel expenses, as in the past..  If you plan to attend – and we do hope you will – kindly return the form to our attention.     ******************************* Trudi R. Bostian Staff Assistant Harvard Electricity Policy Group 79 John F. Kennedy Street Cambridge, MA 02138 P: 617-496-6760 E: trudi_bostian@hks.harvard.edu   REGISTRATION FORM HEPG SEVENTY-FOURTH PLENARY SESSION THURSDAY AND FRIDAY, FEBRUARY 27-28, 2014 SHUTTERS ON THE BEACH SANTA MONICA, CALIFORNIA TO: HARVARD ELECTRICITY POLICY GROUP John F. Kennedy School of Government FROM: Name Title Affiliation Address Phone E-mail ______YES, I will be able to attend the HEPG Plenary Session. ______ NO, I will not be able to attend the meeting. ______ I would like to send my designee: Name Title Address Phone E-mail ___________________________ ___________________________ ___________________________ ___________________________ ___________________________ ___________________________ HOTEL INFORMATION The conference will take place at Shutters on the Beach in Santa Monica, California. The hotel is located at One Pico Boulevard in Santa Monica, and is accessible from the Los Angeles airport. We can cover lodging for Wednesday and Thursday evening. To make your reservation, please contact Trudi Bostian (Trudi_bostian@hks.harvard.edu) and indicate which nights you need. Hotel deadline is: January 28, 2014. To register for the session, please fax or e-mail this reply form to: Jo-Ann Mahoney, HEPG Program Director Fax: (617) 495-1635 Phone: (617) 495-1390 email to: jo-ann_mahoney@harvard.edu