From: To: Subject: Date: Teresa Tenbrink "Bruner, Hannah" RE: HEPG Dates Monday, October 26, 2015 2:39:00 PM Hi Hannah,   Chairman Bitter Smith asked me to let you know that she is unable to attend the session in December.  Thanks for the invitation!   Teresa Tenbrink Executive Aide to Chairman Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625       From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Friday, October 23, 2015 7:44 AM To: Teresa Tenbrink Subject: RE: HEPG Dates   Good morning, Teresa, The next session will be held on Thursday and Friday, December 10-11 at the Four Seasons in Palm Beach, FL. As always, we hope Chairman Bitter Smith will be able to attend. I will be sending out formal invitations next week, but I’m going to go ahead and attach the registration form here. Thank you, and have a great weekend. Best wishes, Hannah   From: Teresa Tenbrink [mailto:ttenbrink@azcc.gov] Sent: Thursday, October 22, 2015 4:35 PM To: Bruner, Hannah; Mahoney, Jo-Ann Subject: HEPG Dates   Hi,   Chairman Bitter Smith asked me to find out when and where the next scheduled HEPG session for planning purposes.  Can you provide them?   Thanks,   Teresa Tenbrink Executive Aide to Chairman Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542/3625 From: To: Subject: Date: Susan Bitter Smith Teresa Tenbrink Re: HEPG Dates Friday, October 23, 2015 10:10:17 AM Should have scrolled down- sorry! Susan Bitter Smith Chairman of the Arizona Corporation Commission President of the Western Conference of Public Service Commissioners 1200 W. Washington Phoenix, AZ 85007 602-542-3625 From: Teresa Tenbrink Sent: Friday, October 23, 2015 9:58 AM To: Susan Bitter Smith Subject: RE: HEPG Dates Below says Palm Beach, FL.   Teresa Tenbrink Executive Aide to Chairman Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625       From: Susan Bitter Smith Sent: Friday, October 23, 2015 9:58 AM To: Teresa Tenbrink Subject: Re: HEPG Dates   Do we know where?   Susan Bitter Smith Chairman of the Arizona Corporation Commission President of the Western Conference of Public Service Commissioners 1200 W. Washington Phoenix, AZ 85007 602-542-3625 From: Teresa Tenbrink Sent: Friday, October 23, 2015 9:55 AM To: Susan Bitter Smith Subject: FW: HEPG Dates FYI-Dec 10-11   Teresa Tenbrink Executive Aide to Chairman Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625       From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Friday, October 23, 2015 7:44 AM To: Teresa Tenbrink Subject: RE: HEPG Dates   Good morning, Teresa, The next session will be held on Thursday and Friday, December 10-11 at the Four Seasons in Palm Beach, FL. As always, we hope Chairman Bitter Smith will be able to attend. I will be sending out formal invitations next week, but I’m going to go ahead and attach the registration form here. Thank you, and have a great weekend. Best wishes, Hannah   From: Teresa Tenbrink [mailto:ttenbrink@azcc.gov] Sent: Thursday, October 22, 2015 4:35 PM To: Bruner, Hannah; Mahoney, Jo-Ann Subject: HEPG Dates   Hi,   Chairman Bitter Smith asked me to find out when and where the next scheduled HEPG session for planning purposes.  Can you provide them?   Thanks,   Teresa Tenbrink Executive Aide to Chairman Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625       From: To: Subject: Date: Attachments: Teresa Tenbrink Susan Bitter Smith FW: HEPG Dates Friday, October 23, 2015 9:55:00 AM Commissioner Registration Form.docx FYI-Dec 10-11   Teresa Tenbrink Executive Aide to Chairman Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625       From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Friday, October 23, 2015 7:44 AM To: Teresa Tenbrink Subject: RE: HEPG Dates   Good morning, Teresa, The next session will be held on Thursday and Friday, December 10-11 at the Four Seasons in Palm Beach, FL. As always, we hope Chairman Bitter Smith will be able to attend. I will be sending out formal invitations next week, but I’m going to go ahead and attach the registration form here. Thank you, and have a great weekend. Best wishes, Hannah   From: Teresa Tenbrink [mailto:ttenbrink@azcc.gov] Sent: Thursday, October 22, 2015 4:35 PM To: Bruner, Hannah; Mahoney, Jo-Ann Subject: HEPG Dates   Hi,   Chairman Bitter Smith asked me to find out when and where the next scheduled HEPG session for planning purposes.  Can you provide them?   Thanks,   Teresa Tenbrink Executive Aide to Chairman Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542/3625 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 9. 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: Teresa Tenbrink "Bruner, Hannah" RE: HEPG Dates Friday, October 23, 2015 9:53:00 AM Thanks Hannah!  We have workshops and special meetings to schedule.  We didn’t want to schedule something during the next session.   Teresa Tenbrink Executive Aide to Chairman Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625       From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Friday, October 23, 2015 7:44 AM To: Teresa Tenbrink Subject: RE: HEPG Dates   Good morning, Teresa, The next session will be held on Thursday and Friday, December 10-11 at the Four Seasons in Palm Beach, FL. As always, we hope Chairman Bitter Smith will be able to attend. I will be sending out formal invitations next week, but I’m going to go ahead and attach the registration form here. Thank you, and have a great weekend. Best wishes, Hannah   From: Teresa Tenbrink [mailto:ttenbrink@azcc.gov] Sent: Thursday, October 22, 2015 4:35 PM To: Bruner, Hannah; Mahoney, Jo-Ann Subject: HEPG Dates   Hi,   Chairman Bitter Smith asked me to find out when and where the next scheduled HEPG session for planning purposes.  Can you provide them?   Thanks,   Teresa Tenbrink Executive Aide to Chairman Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542/3625 From: To: Cc: Subject: Date: Attachments: Mahoney, Jo-Ann Mahoney, Jo-Ann Bruner, Hannah HEPG Draft Agenda, Registration Confirmation Thursday, September 03, 2015 12:30:55 PM HEPG_10_15_DraftAgenda w Speakers.docx Dear HEPG Participants,   We have received your registration and look forward to seeing you at our Harvard Electricity Policy Group session in Houston on Thursday-Friday, October 1-2, 2015.  Our agenda with speakers is attached.    Our best for the Labor Day weekend, 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 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, ERCOT 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 Mike 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 7:00 pm Reception and Dinner 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? 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: Susan Bitter Smith Teresa Tenbrink Re: HEPG"s October Conference Friday, August 21, 2015 4:10:39 PM Both Susan Bitter Smith Chairman of the Arizona Corporation Commission President of the Western Conference of Public Service Commissioners 1200 W. Washington Phoenix, AZ 85007 602-542-3625 From: Teresa Tenbrink Sent: Friday, August 21, 2015 3:06 PM To: Susan Bitter Smith Subject: RE: HEPG's October Conference Wednesday and Thursday?  Or just Wednesday?   Teresa Tenbrink Executive Aide to Chairman Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625       From: Susan Bitter Smith Sent: Friday, August 21, 2015 12:31 PM To: Teresa Tenbrink Subject: Re: HEPG's October Conference   Thank you- hotel too? Susan Bitter Smith Chairman of the Arizona Corporation Commission President of the Western Conference of Public Service Commissioners 1200 W. Washington Phoenix, AZ 85007 602-542-3625 From: Teresa Tenbrink Sent: Friday, August 21, 2015 10:54 AM To: Susan Bitter Smith Subject: FW: HEPG's October Conference I’ll update your calendar and fill  out the registration form.   Teresa Tenbrink Executive Aide to Chairman Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625       From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Friday, August 21, 2015 10:33 AM To: Teresa Tenbrink Subject: HEPG's October Conference   Dear Chairman Bitter Smith, 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?       Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu   From: To: Subject: Date: Teresa Tenbrink "Bruner, Hannah" RE: HEPG"s October Meeting Thursday, August 13, 2015 2:25:00 PM Hi Hannah,   Chairman Bitter Smith would love to attend!   Teresa Tenbrink Executive Aide to Chairman Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625       From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Tuesday, August 11, 2015 10:57 AM To: Teresa Tenbrink Subject: HEPG's October Meeting   Dear Ms. Tenbrink,   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 Chairman Bitter Smith would join us. Please extend our sincerest invitation.   Thank you for your time, and have a lovely evening.   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: Susan Bitter Smith Teresa Tenbrink Re: HEPG"s October Meeting Tuesday, August 11, 2015 7:13:00 PM Yes please. RSVP yes Susan Bitter Smith Chairman of the Arizona Corporation Commission President of the Western Conference of Public Service Commissioners 1200 W. Washington Phoenix, AZ 85007 602-542-3625 From: Teresa Tenbrink Sent: Tuesday, August 11, 2015 11:17 AM To: Susan Bitter Smith Subject: FW: HEPG's October Meeting RSVP?   Teresa Tenbrink Executive Aide to Chairman Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625       From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Tuesday, August 11, 2015 10:57 AM To: Teresa Tenbrink Subject: HEPG's October Meeting   Dear Ms. Tenbrink,   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 Chairman Bitter Smith would join us. Please extend our sincerest invitation.   Thank you for your time, and have a lovely evening.   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: Teresa Tenbrink "Bruner, Hannah" RE: Reimbursement Wednesday, July 15, 2015 9:12:00 AM Please send it to 1200 W. Washington, Phoenix, AZ 85007.  Thanks!   Teresa Tenbrink Executive Aide to Chairman Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625       From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Wednesday, July 15, 2015 8:41 AM To: Teresa Tenbrink Subject: Reimbursement   Good morning, Teresa, I received the reimbursement forms in the mail today. Thank you! To which address should we send the check? Best,   Hannah Bruner Staff Assistant Harvard Electricity Policy Group Harvard Kennedy School (617) 496-6760 Hannah_Bruner@hks.harvard.edu   From: To: Subject: Date: Teresa Tenbrink "Bruner, Hannah" RE: Travel Reimbursement for HEPG"s 79th Plenary Session in DC Wednesday, July 08, 2015 4:12:00 PM Hi Hannah,   I’m sending reimbursement in the mail today.  Thanks so much!   Teresa Tenbrink Executive Aide to Chairman Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625       From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Tuesday, July 07, 2015 10:34 AM To: Teresa Tenbrink Subject: Travel Reimbursement for HEPG's 79th Plenary Session in DC     Good afternoon,   HEPG is delighted Chairman Bitter Smith was able to join us for the HEPG conference in Washington, DC and hope she enjoyed the sessions.   HEPG is happy to reimburse her or the commission for her 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: Teresa Tenbrink jo-ann_mahoney@harvard.edu 2016 Dates Thursday, July 02, 2015 2:43:00 PM Hi Jo-Ann,   Just curious to see if you had any specific dates for the HEPG events in 2016.  I am putting together our Meeting schedule for the year and don’t want our dates to conflict with HEPG.   Thanks so much!   Teresa Tenbrink Executive Aide to Chairman Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625       From: To: Cc: Subject: Date: Attachments: Janet Wagner Shaylin A. Bernal Laurie Woodall; Janice Alward FW: Wednesday, June 24, 2015 12:08:21 PM 6-25-15jnt.doc Shay, this looks fine.  Thanks!   From: Shaylin A. Bernal Sent: Wednesday, June 24, 2015 11:52 AM To: Janet Wagner Subject: RE: Janet,   See the notice attached and let me know if any revisions are needed.   Shay   From: Janet Wagner Sent: Wednesday, June 24, 2015 11:42 AM To: Shaylin A. Bernal Cc: Teresa Tenbrink; Laurie Woodall; Susan Bitter Smith; Janice Alward Subject: FW: Shay, I think that we normally do a notice of joint appearance for this sort of thing.  See below.  I’ll come by.   From: Teresa Tenbrink Sent: Wednesday, June 24, 2015 9:40 AM To: Laurie Woodall; Janet Wagner; Janice Alward Cc: Susan Bitter Smith Subject: RE: Please see attached.   Mandarin Oriental 1330 Maryland Ave Sw, Washington, DC 20024   Teresa Tenbrink Executive Aide to Chairman Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625       From: Laurie Woodall Sent: Wednesday, June 24, 2015 9:36 AM To: Janet Wagner; Janice Alward Cc: Susan Bitter Smith; Teresa Tenbrink Subject: FW: I am getting the address of the hotel from Teresa. Let me know if you need additional information in order to prepare what I presume will be a Notice of a Joint Appearance of a Quorum of Commissioners.   From: Susan Bitter Smith Sent: Tuesday, June 23, 2015 8:35 PM To: Janice Alward; Laurie Woodall Subject: Janice I just learned tonight that contrary to what I thought- a third Commissioner will be at the Harvard Electricity Policy Group in Washington DC on Thursday and Friday. Commissioner Little is going as well as Bob Stump and myself. None of us are speaking.‎ The location is the Mandarin Oriental Hotel in DC.   Can we get the appropriate posting done? Thanks. Susan   Susan Bitter Smith Chairman of the Arizona Corporation Commission President of the Western Conference of Public Service Commissioners 1200 W. Washington Phoenix, AZ 85007 602-542-3625 COMMISSIONERS SUSAN BITTER SMITH – Chairman BOB STUMP BOB BURNS DOUG LITTLE TOM FORESE JODI JERICH EXECUTIVE DIRECTOR ARIZONA CORPORATION COMMISSION Notice of a Joint Appearance of a Quorum of Commissioners (Not an Official Meeting of the Arizona Corporation Commission) June 25 - 26, 2015 Location: Mandarin Oriental 1330 Maryland Ave SW Washington, D.C. This notice is provided as a courtesy to the public that three or more Commissioners may be present at the above location to attend the Harvard Electricity Policy Group Plenary Session. There will be a hosted evening reception and dinner on June 25, 2015 at the Decatur Carriage House on Lafayette Square. The Commissioners attending this meeting and reception will not vote on any issue or discuss pending legal actions of the Arizona Corporation Commission. 1200 WEST WASHINGTON STREET; PHOENIX, ARIZONA 85007-2927 / 400 WEST CONGRESS STREET; TUCSON, ARIZONA 85701-1347 www.azcc.gov From: To: Cc: Subject: Date: Mahoney, Jo-Ann Susan Bitter Smith Bruner, Hannah RE: HEPG Agenda and Dinner Invitation Friday, June 19, 2015 11:38:42 AM Susan, We would be happy to have your daughter join us for dinner.  We may have a space constraint, but I think it should be fine.  Can we wait for a definitive yes?   Best, Jo-Ann From: Susan Bitter Smith [SBitterSmith@azcc.gov] Sent: Friday, June 19, 2015 2:19 PM To: Mahoney, Jo-Ann Cc: Bruner, Hannah Subject: RE: HEPG Agenda and Dinner Invitation Jo- Ann and Hannah, I will have my husband and my 21 year old daughter with me in DC because we are going on from there to another conference.  I have not had guests at any earlier HEPG functions, is it possible to bring both of them?  I am happy to pay for dinner for the third if that helps.  Thanks. Susan   Susan Bitter Smith Chairman Arizona Corporation Commission President of the Western Conference of Public Service Commissioners 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   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     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: Bruner, Hannah Teresa Tenbrink RE: HEPG Next week Tuesday, June 16, 2015 10:50:14 AM Hi, Teresa, The Chairman is on our master account, so her room is taken care of. Best, Hannah   From: Teresa Tenbrink [mailto:ttenbrink@azcc.gov] Sent: Tuesday, June 16, 2015 1:49 PM To: Bruner, Hannah Subject: RE: HEPG Next week   Hi Hannah,   Will this be charged to HEPG or to the Chairman?   Teresa Tenbrink Executive Aide to Chairman Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625       From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Tuesday, June 16, 2015 10:38 AM To: Teresa Tenbrink Subject: RE: HEPG Next week   Hello, Teresa, Please find attached the most recent version of the agenda. The Chairman’s hotel reservation number is 47M1WU. Check-in is 3:00 pm on Wednesday, June 24, and check-out is 12:00 pm on Friday, June 26. Please let me know if you have any other questions. Best wishes, Hannah   From: Teresa Tenbrink [mailto:ttenbrink@azcc.gov] Sent: Tuesday, June 16, 2015 12:45 PM To: Bruner, Hannah Subject: HEPG Next week   Hi Hannah,   I have not received confirmation about the HEPG event next week.  Do you have the hotel reservations for the Chairman? I am putting together her travel details.    Thanks,   Teresa Tenbrink Executive Aide to Chairman Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625       From: To: Subject: Date: Attachments: Bruner, Hannah Teresa Tenbrink RE: HEPG Next week Tuesday, June 16, 2015 10:36:12 AM HEPG_6_15_DraftAgenda w Speakers.docx Hello, Teresa, Please find attached the most recent version of the agenda. The Chairman’s hotel reservation number is 47M1WU. Check-in is 3:00 pm on Wednesday, June 24, and check-out is 12:00 pm on Friday, June 26. Please let me know if you have any other questions. Best wishes, Hannah   From: Teresa Tenbrink [mailto:ttenbrink@azcc.gov] Sent: Tuesday, June 16, 2015 12:45 PM To: Bruner, Hannah Subject: HEPG Next week   Hi Hannah,   I have not received confirmation about the HEPG event next week.  Do you have the hotel reservations for the Chairman? I am putting together her travel details.    Thanks,   Teresa Tenbrink Executive Aide to Chairman Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625       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? 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: Attachments: Bruner, Hannah Susan Bitter Smith RE: Please send Susan the presentations she is asking for below Monday, June 15, 2015 6:48:17 AM 3_Bie.pdf 3_Klass.pdf 3_Shanker.pdf Good morning, Chairman, I hope you've had a nice weekend. Please find attached the presentations on ISO Governance given at the last HEPG meeting. I hope this helps. Have a great start to your week. Best regards, Hannah -----Original Message----From: Susan Bitter Smith [mailto:SBitterSmith@azcc.gov] Sent: Saturday, June 13, 2015 2:21 PM To: Brown, Ashley; Bruner, Hannah Subject: Re: Please send Susan the presentations she is asking for below Thanks so much. Looking forward to seeing you in DC. Susan Susan Bitter Smith Chairman of the Arizona Corporation Commission President of the Western Conference of Public Service Commissioners 1200 W. Washington Phoenix, AZ 85007 602-542-3625 From: Brown, Ashley Sent: Friday, June 12, 2015 10:22 PM To: Bruner, Hannah Cc: Susan Bitter Smith Subject: Please send Susan the presentations she is asking for below T-Mobile. America's First Nationwide 4G Network. ------ Original message-----From: Susan Bitter Smith Date: Fri, Jun 12, 2015 21:03 To: Brown, Ashley; Subject: ‎Ashley- hope all is well. As you may have heard, APS has decided to join the EIM. At the last HEPG group there were some presentations given on ISO governance and I brought them back to AZ, provided them to staff and of course now no one can find them. Would it be possible for someone to send me those presentations or the link to those materials? Anything else you might have on regional market governance would also be valuable.Thanks so much. Susan Susan Bitter Smith Chairman of the Arizona Corporation Commission President of the Western Conference of Public Service Commissioners 1200 W. Washington Phoenix, AZ 85007 602?542-3625 NYISO Governance Board members and all employees are independent, with no business, financial, operating or other direct relationship to any Market Participant or stakeholder Board of Directors President & CEO NYISO Staff 10-member Board of Directors with experience in energy, environment, finance, academia, technology and communications Management Committee Operating Committee Business Issues Committee Market Participant stakeholder committees of individuals from market sectors: Transmission Owners, Generation Owners, Other Suppliers, End-Use Consumers, and Public Power & Environmental Parties 1 Sub-Committees, Working Groups & Task Forces MANAGEMENT COMMITTEE BUSINESS ISSUES COMMITTEE Billing and Accounting Working Group Installed Capacity (ICAP) Working Group Market Issues Working Group Price-Responsive Load Working Group Electric System Planning Working Group Interconnection Issues Task Force Credit Policy Task Force Board Liaison Committee Budgets and Priorities Working Group By- Laws Subcommittee Market Participant Audit Advisory Subcommittee Tariff Review Subcommittee Stay Review Subcommittee Board Selection Subcommittee OPERATING COMMITTEE Communication and Data Advisory Subcommittee Transmission Planning Advisory Subcommittee System Operations Advisory Subcommittee System Protection Advisory Subcommittee Electric System Planning Working Group Restoration Working Group Interconnection Project Cost Allocation Study WG Reactive Power Working Group Interconnection Issues Task Force 2 NYISO Voting Sectors By Market Sector End-Use Consumers 20%: Other Suppliers 21.5% Generation Owners 21.5% Small Consumers (4.5%) Power Authorities (8%) Municipals & Co-ops (7%) Government Advocate & Retail Aggregators (1.8%) State-wide Advocate (2.7%) Public Power 17%: Transmission Owners 20% Environmental Parties (2%) Large Consumers - Industrial (9%) Large Consumers - Government (2%) 58% required to pass 3 Role of the Board  Oversee management of the NYISO, including the reliable/efficient operation of the electric transmission system and electricity markets.  Communicate clear policies and goals to the CEO  Provide strategic guidance to the NYISO and its officers.  Ensure NYISO’s financial affairs are conducted in a manner consistent with sound financial and accounting practices, law, and effective risk management. 4 Role of the Board (cont.)  Ensure that the corporation operates in the public interest, observes the highest ethical standards and complies with its Code of Conduct.  Ensure that the Board and the corporation are independent of any market participant, sector of Market Participants or the economic interest of any such participant or sector.  Select officers of the NYISO, including evaluating and approving the compensation and terms of employment of such officers. 5 Role of the Board (cont.)  Oversee filings with FERC and other regulatory agencies.  Hear appeals from actions of market participant committees.  NYPSC or FERC may attend and participate, but may not vote, in Board meetings. 6 RTOs and ISOs: Uniformity, Regionalization, and Future Challenges Alexandra B. Klass University of Minnesota Law School March 2015 Calti-rniu ISO Electric Reliability Council Oi Texas IIDIITID Regional Transmission Organization Jurisdiction Customers Generation capacity Miles of Transmission Lines PJM Multi-state 61 million 183,000 MW 63,000 ISO-NE Multi-state 14 million 32,000 MW 8,000 MISO Multi-state 48 million 205,759 MW 65,000 SPP Multi-state 15 million 77,366 MW 48,000 ERCOT Single state 23 million 84,000 MW 40,530 CA-ISO Single state 30 million 59,000 MW 25,865 NYISO Single state 19.5 million 37,925 MW 11,005 Stakeholders Electric System Key Actors in RTO Decision Making RTO/ISO Generation Utilities Distribution Utilities State- PUC, Energy Office (Policies &Planning), Environmental Office (Siting) Industrial, Commercial & Residential Consumers FERC Federal and State Courts Civil Society Stakeholders Stakeholder Classes PJM (5) MISO (10) • • • • • • Transmission Owners • Generation Owners/Independent Power Producers • Power Marketers • Transmission Dependent Utilities (munis/co-ops) • Eligible End Use Customers • Coordinating Members • Transmission Developers • State Regulators (OMS)* • Consumer Advocates* • Environmental/Other* Transmission Owners Generation Owners Electricity Distributors End Use Sectors Others CAISO (6) • • • • • • • Transmission Owners Generation Owners Transmission Dependent Utilities End Users & Retail Energy Providers Alternative Energy Providers Public Interest Groups Marketers * Non Paying Critical dimensions of RTO/ISO differences • • • • • Single or multi-state Member state politics/interests Traditionally structured or restructured markets RTO member, voting and advisory structure RTO stakeholder interests, power and opportunities • Role of FERC (and shifting politics of FERC) • Dominant fuel source with state/RTO/ISO Electric Power Net Generation by State (2012) - Geadlerrml I Hrdmelxmz Gama-morn] I Cu: I Petroleum I Mped?ulw Sula and Film-volt!? Wind I mud and'qurd Di?hud Fuel: 2012 U.S. Average Electricity Retail Prices (cents per kilowatt hcur) chmem I 12mm14m I am tn 9.5a I 14111 tn 35m I 9.51 11112.00 Electricity Restructuring by State Snurce: Administration United States - Annual Average Wind Speed at 80 Wind Speed rrv's >105 10.0 9.5 a" Source: Wind resource estimates developed by AWS Truepower, LLC for windNavigator?. Web: http?wvmwindnavigatorcom Spatial resolution of wind resource data: 2.5 km. Projection: Albers Equal Area WGSB4. 0 .AWS Truepower E: . 'a . Where science delivers performance. NATIONAL RENEWABLE ENERGY LABORATORY Ell APR-2011 2.1.1 U.S. Wind Power Capacity Installations by State American Wind Energy Association, Fourth Quarter 2014 Thanrn??ngEmumLmidmm?wthi1BEF Compusite Wind Resource Map Existing TEE k'u' New TEE kiln" RUDE-AC Link Wir?FmarCIa-mi?mtim Wind Rim-rm wmw' Puuriu Elml'l'l ?an wkn? mm 2 Hugh: 33- mm 53-33 El- Fl'r Sim-11m Til a rim-d uni-5m 5 Exodus-I11 saw?am 15- an cumming Ear-3m an-aa sin-am aim-1m 5.3.11.1 plum-inani- ?lwih?nwmi 3? ?film 12.5 1-43-15? 15.? ?ll-13 Haw :I?m?n mel?m 153-119 1IQ-1QT ?Nauru:- United States transmission grid Source: FEMA ?Nlnd Speed mils Source: Wind resource es?mates developed by AWS Truepower, LLC. Web: htlp1JMww.awsiruapower.oom. Map developed by NREL. Spatial resolution ofwind resource data: 2.0 km. Projection: Albers Equal Area WGSB4. Conceptualizing RTOs/ISOs • Agents of FERC: Entity delegated regulatory power from FERC • Monopolists: Entities with monopoly power over transmission operations/markets that must be regulated by FERC • Hybrids: Created by FERC regulation and market participants in region • Agents of transmission owners in a region • Regional planning entity for transmission (Dworkin & Goldwasser, 2007) Future Challenges for RTOs/ISOs • Regional approaches to EPA’s Clean Power Plan • Enhanced Transmission Planning Role • New Regional Transmission Permitting/Siting Role??? • Queries: – What is the impact of existing RTO/ISO governance structures on addressing these challenges? – Do benefits of uniformity override regional needs? States GRANTING Right of Eminent Domain to Merchant Transmission Lines By STATUTE Florida, Kentucky, Michigan, Montana, New Mexico, Oregon, Rhode Island, Vermont, & Wisconsin By PUC Order Kansas & Oklahoma Examples: • • • MICHIGAN (MICH. COMP. LAWS ANN § 486.255) - “… an independent transmission company or an affiliated transmission company shall have the power to condemn property that is necessary to transmit electric energy for public use…” NEW MEXICO (N.M. STAT. ANN. § 62-16A-4 (B)(8)) - The New Mexico Renewable Energy Transmission Authority may, “pursuant to the provisions of the Eminent Domain Code, exercise the power of eminent domain for acquiring property or rights of way for public use if needed for projects if such action does not involve taking utility property or does not materially diminish electric service reliability of the transmission system in New Mexico, as determined by the public regulation commission.” RHODE ISLAND (R.I. GEN. LAWS ANN. § 39-1-2(13)) – “‘Electric transmission company’ means a company engaging in the transmission of electricity or owning, operating, or controlling transmission facilities. An electric transmission company shall not be subject to regulation as a public utility except as specifically provided in the general laws, but shall be regulated by the federal energy regulatory commission and shall provide transmission service to all nonregulated power producers and customers, whether affiliated or not, on comparable, nondiscriminatory prices and terms. Electric transmission companies shall have the power of eminent domain exercisable following a petition to the commission pursuant to § 39-1-31.” States DENYING Right of Eminent Domain to Merchant Transmission Lines By STATUTE Illinois, Maryland, New Hampshire, Nebraska By PUC Order Arkansas & Connecticut Bans INTRASTATE merchant eminent domain ONLY New York Limited eminent domain for ANY transmission lines Delaware Examples: • • • • ILLINOIS (220 ILL. COMP. STAT. § 5/8-509, § 5/8-406.1(a), § 5/3-105(b)(7)): A “qualifying facility” (as defined by PURPA) is not a public utility and thus lacks eminent domain authority. (PURPA, 18 C.F.R. § 292.101(b)(i)) – A “qualifying facility” includes transmission lines that “directly and indirectly interconnect [with] electric utilities.” NEBRASKA (NEB. REV. STAT. § 70-1014.02(6), § 70-1014.02(1)(a)): “[O]nly an electric supplier may exercise its eminent domain authority to acquire the land rights necessary for the construction of transmission lines and related facilities to provide transmission services for a certified renewable export facility. The exercise of eminent domain to provide needed transmission lines and related facilities for a certified renewable export facility is a public use. Nothing in this section shall be construed to grant the power of eminent domain to a private entity.” “Electric supplier means a public power district, a public power and irrigation district, an individual municipality, a registered group of municipalities, an electric membership association, or a cooperative.” NEW HAMPSHIRE (N.H. REV. STAT. ANN. § 371:1) – “No public utility may petition for permission to take private land or property rights for the construction or operation of an electric generating plant or an electric transmission project not eligible for regional cost allocation, for either local or regional transmission tariffs, by ISO-New England or its successor regional system operator.” CONNECTICUT (Transenergie U.S. Ltd. 2000 WL 33121599 (Conn. D.P.U.C.) (2000)) – State P.U.C. held that merchant line Transenergie was not an “electric distribution company,” and as such, lacked the right of eminent domain. States MIGHT Grant Right of Eminent Domain to Merchant Transmission Lines STRONGER likelihood of eminent domain authority Arizona, Colorado, Idaho, Indiana, Iowa, Massachusetts, South Dakota, Tennessee, Texas, West Virginia, & Wyoming WEAKER likelihood of eminent domain authority California, Hawaii, Minnesota, Nevada, & Pennsylvania NEUTRAL & UNCLEAR Alabama, Alaska, Georgia, Louisiana, Maine, Mississippi, Missouri, New Jersey, North Carolina, North Dakota, Ohio, South Carolina, Utah, Virginia & Washington. Examples: • • • COLORADO (COLO. REV. STAT. ANN. § 38-2-101) – “ If any corporation formed for the purpose of constructing a road, ditch, reservoir, pipeline, bridge, ferry, tunnel, telegraph line, railroad line, electric line, electric plant, telephone line, or telephone plant is unable to agree with the owner for the purchase of any real estate or right-of-way or easement or other right necessary or required for the purpose of any such corporation for transacting its business or for any lawful purpose connected with the operations of the company, the corporation may acquire title to such real estate or right-of-way or easement or other right in the manner provided by law for the condemnation of real estate or right-of-way.” MINNESOTA (In re Prairie Rose Transmission, LLC, 2012 WL 258025 (Minn. P.U.C., Jan. 13, 2012)) – The Minn. PUC granted a certificate of need for a private transmission project that would connect Prairie Rose Wind Farm to the grid, but noted that the company would not have eminent domain authority. The PUC did not explain why not, or whether the company had sought eminent domain authority for the line. WYOMING (Bridle Bit Ranch Co. v. Basin Elec. Power Co-op., 118 P.3d 996, 998, 1003 (Wyo. 2005)) – The WY supreme court held that a wholesale electric generation and transmission cooperative was not a public utility, and therefore did not need a certificate of public necessity and convenience, but that it could exercise eminent domain regardless. Eminent Domain For Merchant Transmission Lines Providers Allowed by Statute Allowed by PUC Order Merchant Eminent Domain LIKELY Unclear Intrastate Merchant Lines ONLY Banned Merchant Eminent Domain UNLIKELY Banned by PUC Order Banned by Statute Limited Eminent Domain for Any Transmission Stakeholder Processes: A Good Idea, But… 0 ROY J. SHANKER HARVARD ELECTRICITY POLICY GROUP MARCH 25, 2015 I Raga 0 ?am a new: I a '3 is Basic Concept is Great—What’s Not To Like? 2  Basic objective for extensive stakeholder processes was associated with creation of ISO’s/RTO’s and need for broad support/ “buy-in”  Stated general goals sounded good: (e.g. PJM)       Educate stakeholders on a wide range of issues related to PJM markets, operations, public policies and industry matters; Explore different solutions, building consensus which helps policy makers approve key laws and regulations; Improve communication among Members and between Members [RTO/Board]; Implement the powers and responsibilities of the Members Committee and other committees defined in the OA… Create technically sound solutions. E.g. Improve/evolve markets and increase efficiency Educate stakeholders on a wide range of issues 3  …related to markets, operations, public policies and industry matters  Valuable activity for market participants and regulators   Some market elements are complicated, rules have grown enormously, Only a small minority of stakeholders may understand or capture the full market design  Continuing education improves efficiency in participation, compliance with regulatory objectives, and efficiency in understanding needed change Explore different solutions, … 4  Identify problems, discuss solutions;  Explore different solutions;  Improve communications;  All reasonable activities that you would expect would improve operation of market and participants understanding and decision making But… 5  Chose your aphorism, unfortunately most apply:  “Murphy’s Law” of Unintended Consequences  "Easy is the descent into Hell, for it is paved with good intentions.” Milton-Paradise Lost, published 1667.  “No good deed goes unpunished” (Oscar Wilde or Clare Boothe Luce or …)  “Justice delayed is justice denied”, Gladstone or William Penn and indirectly Martin Luther King  “Be careful what you wish for.” But… 6  Much of the problem lies with the explicit objective of consensus building and consensus decision making  This is not a realistic goal in context of electricity markets and is the major flaw in all stakeholder processes.  Most (not all) decisions addressed by stakeholders and RTOs relate to Pareto “like” efficiency or optima—No party can benefit without a shift of costs to others—  Win/win issues are infrequent, and often seen as win/lose regardless But… 7  Negotiation and development of transfer payments, or related allocation of costs with complex/simultaneous causality is simply not amenable to consensus processes where the underlying real concern of participants is “who pays?”  Similarly, consensus building is not very relevant to issues where there is a “clean question” and a “right” analytic answer. But… 8  Mixed governance structures make this even worse.   Super majority rules create a form of market power Self-interest is all that is required for participation and delay  The Commission amplifies the problem by conveniently blessing or condemning decisions based on stakeholder decision either where it is expedient or where they appear reluctant to make a decision  RTO’s and participants play the same game: “consensus is good when you agree with me”,  Otherwise stalling is acceptable, maybe the issue will just go away, or parties just develop their litigation positions  Makes difficult fixing even known flaws/problems But… 9  The net result is that another layer of bureaucracy, delay and expense has been added to an existing slow decision process  The cost is staggering. At least 1 meeting per day that may engage 100 professionals (plus support staff ), plus overheads, plus preparation, etc. at just one RTO.  This expense, delay and inefficiency is particularly true when faced with large potential shift of costs (e.g. billions). Achieving no result is perceived as the preferred alternative to creating any uncertainty about exposure to change in cost allocations/responsibility.  This often undercuts issues where there may be “win/win” solutions We Knew This Would Happen-But… 10  There are over 100 years of state and about 80 years of federal precedent on how “well” consensus works in contested proceedings.   Never seemed to be a shortage of state or federal litigation despite pressure to settle Settlements (via consensus or directed by regulators) often produce horrible results  There were no real reasons other than the politics of perception for creating these powers in stakeholder processes  The fundamental issues of who pays and who gets paid have remained unchanged in everyone’s mind and still ultimately go to the Commission Widespread Frustration 11  Fundamentally, I bear some of the blame for not articulating the story well enough, but FERC bears most of the blame, and FERC is not doing its job in setting priorities in setting these principles and enforcing these processes to create efficient markets. It is deferring too much to stakeholder processes and bottom-up and consensus agreement. It is a big mistake and it is hurting us more and more and is causing more and more problems. We need leadership at FERC to solve this problem. (William Hogan, Jan 7, Technical Session) Anything Constructive From Experience? 12  YES—Sort of.  Once you recognize the non-constructive impact of consensus seeking in these situations and the need for regulatory process regardless, simply move to a stakeholder process with:       Well defined timeline-beginning with problem statements RTO as lead designer Education Participant Input with RTO for Solution One or two “cycles” of comment and revision Well defined End: Tariff Submission with all necessary authority held by the RTO  Looks a lot like PJM Enhanced Liaison Process  Set deadlines, allow/but limit debate, move forward From: To: Subject: Date: Attachments: Susan Bitter Smith Teresa Tenbrink Fw: HEPG Conference Logistics/Dinner Invitation Friday, March 06, 2015 2:41:13 PM HEPG_3_15_DraftAgenda_Speakers.docx CaliforniaRoadmap_2014.pdf ‎For the materials- I have rsvp'd already for the dinner. Susan Bitter Smith Chairman of the Arizona Corporation Commission President of the Western Conference of Public Service Commissioners 1200 W. Washington Phoenix, AZ 85007 602-542-3625 From: Mahoney, Jo-Ann Sent: Friday, March 6, 2015 1:29 PM 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 Teresa Tenbrink Chairman Bitter Smith"s Room Reservation for HEPG"s March Meeting Thursday, February 26, 2015 8:14:03 AM Dear Teresa,    We have confirmed Chairman Bitter Smith’s stay at the Ritz-Carlton in Half Moon Bay, CA for Monday and Tuesday evening. Her confirmation number is  82568740. 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: Attachments: Susan Bitter Smith Teresa Tenbrink Fw: HEPG Confirmation of March Attendance Wednesday, February 04, 2015 1:04:11 PM HEPG_3_15_DraftAgenda.docx HEPG_3_15_DraftAgenda.pdf Susan Bitter Smith Chairman of the Arizona Corporation Commission Chairman of the Western Conference of Public Service Commissioners 1200 W. Washington Phoenix, AZ 85007 602-542-3625 From: Mahoney, Jo-Ann Sent: Wednesday, February 4, 2015 12:55 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 Bruner, Hannah “Valuation of Distributed Solar: A Qualitative View” Wednesday, February 04, 2015 11:51:46 AM 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: Bruner, Hannah Bruner, Hannah Important Information for HEPG"s March 2015 Conference Friday, January 30, 2015 11:08:03 AM Commissioner Registration_form_3 15.docx 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: Subject: Date: Bruner, Hannah Teresa Tenbrink RE: Reimbursement for Conference Travel Friday, December 12, 2014 12:03:21 PM Thank you, Teresa, I’ve entered the request for reimbursement into the financial system and will be looking for the forms in the mail. Thank you, again, and have a wonderful weekend. Best, Hannah   From: Teresa Tenbrink [mailto:ttenbrink@azcc.gov] Sent: Friday, December 12, 2014 1:46 PM To: Bruner, Hannah Subject: RE: Reimbursement for Conference Travel   Hi Hannah,   I’ve sent Commissioner Bitter Smith’s reimbursement in the mail today.  I have also attached it.  Thanks,   Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Wednesday, December 10, 2014 8:35 AM To: Susan Bitter Smith Cc: Teresa Tenbrink Subject: Reimbursement for Conference Travel   Dear Commissioner Bitter Smith,   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: Beth L. Soliere Teresa Tenbrink RE: Reimbursement for Conference Travel Wednesday, December 10, 2014 2:11:52 PM 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: Mahoney, Jo-Ann Mahoney, Jo-Ann Bruner, Hannah HEPG: Reading from Bruce Edelston Monday, December 01, 2014 12:33:18 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: Bruner, Hannah Teresa Tenbrink RE: Commissioner Bitter Smith"s Conference Reimbursement Friday, November 14, 2014 10:46:47 AM Hi, Teresa, I apologies for the delayed response. Commissioner Bitter Smith’s reimbursement has been approved for issuing payment, so it should be sent soon. I will request a timeline for arrival. Thanks, and have a nice weekend. Best wishes, Hannah   From: Teresa Tenbrink [mailto:ttenbrink@azcc.gov] Sent: Thursday, November 13, 2014 2:55 PM To: Bruner, Hannah Subject: RE: Commissioner Bitter Smith's Conference Reimbursement   Hi Hannah,   I’m checking on the reimbursement that I sent in the mail on Oct 29th.  Can you check on the status of it?   Thanks,   Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Wednesday, October 29, 2014 10:23 AM To: Teresa Tenbrink Subject: RE: Commissioner Bitter Smith's Conference Reimbursement   Great—thank you, Teresa!   From: Teresa Tenbrink [mailto:ttenbrink@azcc.gov] Sent: Wednesday, October 29, 2014 1:22 PM To: Bruner, Hannah Subject: RE: Commissioner Bitter Smith's Conference Reimbursement   Hi Hannah,   I’ve put the receipts in the mail today to your attention at the address below.  Thank you!   Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Wednesday, October 29, 2014 6:55 AM To: Teresa Tenbrink Subject: RE: Commissioner Bitter Smith's Conference Reimbursement   Good morning, Teresa, That will be perfect. Please mail them to the following address:                 Hannah Bruner                 Staff Assistant, HEPG                 79 JFK St.                 Mailbox 84                 Cambridge, MA 02138 Thank you, Teresa. Also, I have received Commissioner Bitter Smith’s registration form for the December conference. Thank you for sending it so quickly. We are very pleased she is able to attend. Have a wonderful day. Regards, Hannah   From: Teresa Tenbrink [mailto:ttenbrink@azcc.gov] Sent: Tuesday, October 28, 2014 3:25 PM To: Bruner, Hannah Subject: RE: Commissioner Bitter Smith's Conference Reimbursement   I can send the original receipts in the mail.  Will that work?    Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Tuesday, October 28, 2014 7:13 AM To: Teresa Tenbrink Subject: Commissioner Bitter Smith's Conference Reimbursement   Dear Teresa, Good morning. I’ve been informed that the Harvard Kennedy School’s finance department requires original receipts or completion of the Missing Receipt Affidavit (with a copy of the receipt) for all meals over $25. I’ve attached a pdf of the Missing Receipt form. I went ahead and completed the form based on the copy of the receipt for the meal at the The Red House you sent over, so all I need is your signature at the bottom of the form. If you could just sign it and send it back, that would be great. Thank you! 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: Beth L. Soliere Teresa Tenbrink FW: HEPG New Orleans: Deadline October 31, panel descriptions Monday, November 10, 2014 2:18:41 PM     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: Teresa Tenbrink "Bruner, Hannah" RE: Reimbursement Forms Monday, October 20, 2014 10:26:00 AM Great!  Thanks Hannah.    Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Monday, October 20, 2014 10:18 AM To: Teresa Tenbrink Subject: RE: Reimbursement Forms   Hello, Teresa, Thank you for your response. That’s perfectly fine. I will touch base with her to see where she is with getting it back to you. Trudi has moved on to a different position, so I’ve taken over as Staff Assistant for HEPG. So, if I can ever be of any assistance, please let me know. Thank you, Teresa. Best, Hannah   From: Teresa Tenbrink [mailto:ttenbrink@azcc.gov] Sent: Monday, October 20, 2014 1:05 PM To: Bruner, Hannah Subject: RE: Reimbursement Forms   Hi Hannah,   I sent Commissioner Bitter Smith’s reimbursement form to Trudi on Oct. 8th.  Should I have sent it to you?  I have attached the email.   Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   From: Bruner, Hannah [mailto:Hannah_Bruner@hks.harvard.edu] Sent: Monday, October 20, 2014 9:08 AM To: Teresa Tenbrink Subject: Reimbursement Forms   Dear Teresa, Commission Bitter-Smith does not need to complete the W9 form, as she is already in our system. I apologize for the confusion. Please advise me if I can be of any assistance. 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: Teresa Tenbrink Peter Vazquez Fwd: Expense Form Thursday, October 09, 2014 1:11:10 PM SKM_C654e14100809300.pdf Hi Peter, Here is the reimbursement form that I sent to HEPG. The receipts are attached.  Sent from my Verizon Wireless 4G LTE smartphone -------- Original message -------From: Teresa Tenbrink Date:10/08/2014 9:35 AM (GMT-07:00) To: "'Bostian, Trudi'" Subject: Expense Form Hi Trudi,   Please find attached Commissioner Bitter Smith’s reimbursement form for her trip Oct 1-3, 2014.    Thanks,   Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   HARVARD UNIVERSITY UNIVERSAL EXPENSE FORM mm PA ENT TYPE (CHECK ONLYONE) Out of Pocket El American Express Corporate Card EMPLOYEE TYPE 0R AFFILIATION CI Harvard Employee CI AffiliatelHarvard StudenthasuallStipend - complete shaded areas Invited Guest/Visitor - complete shaded areas LJ Direct Deposit Reimbursement Method (Check only one) Maper Check Date: Reimbursee or Cardholder Name: Web VoucherlPO#: Qt tier Social SeclTax Harvard US Citizen or Permanent Resident: Yes No Permanent Residents - Resident Alien Card Visa Type: Country of Tax ResidencyCitizen or Permanent Resident, provide: Redacted Personal Information BUSINESS PURPOSE {Detailed reason for expenditure. For travel or entertainment, include person andior organization visited and location. Also include expense date range. List additional business purposes on page 2.) Date(s) of expense(s) #1 [Oil/H Tax] Prom AvoMt-?ln Marv-M #2 wit liq Meat In #3 mm In Cmb?mgMp: #4 Felipe/?9. SUMMARY OF EXPENSES (Room for additional expenses is available on page 2) . . . . Business 23:22:: ?llfiil' $23.2? to 60-00 MW in Rune I332 :5 Meal ?in 36? H3 I 14 MW W630 Subtotals from page 2, if applicable: 6.20 SD 00 LN, .13. 5944:; 6T5. LESS ADVANCES EXPENSE REPORT TOTAL: ILM ?3.qu so ~50 I I I SLILI TOTAL AMOUNT OF RECEIPTS UNDER $75 I 5 I REIMBURSEE: certi$ese are all legitimate Harvard University business expenses. MM: SIGNATURE: ngiwg'VL?. Date: IO/g/i?i? Reimbursee Permanent Legal Address: I200 no. Phoenx, @9307 Reimbursee Cljeck Mailing Address, if different than Legal: Stem shah IZOD to. Merci/elm: Phoenix, /l2 @007 I have reviewed these eApenses and are in accordance with University and Tub policy. Preparer: Phone: Approver: (PRINT) (SIGNA TURE) HARVARD UNIVERSITY UNIVERSAL EXPENSE FORM SUPPLEMENTAL INFORMATION PAGE OF Reimbursee or Cardholder Name: Web Voucher/PO#: Departmental Accou nting The area below is for departments whose ?nancial of?ce requires this information for processing purposes. This information will be captured in the Web Voucher System. Amount Tub (3) Org (5) Object (4) Fund (6) Activity (6) Sub (4) Root (5) Business Purposeit ADDITIONAL BUSINESS PURPOSES OR INFORMATION Dat of #6 #7 #8 #9 ADDITIONAL EXPENSES Business Description Air/Rail Ground Business date detail etc. Travel Trans Lodging Meals Other Total Subtotals, carry to ?rst sheet Hints and policy notes: 1. 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. 2. Please refer to the Policy at a Glance or the complete travel policy at 3. To expedite processing, contact the Travel Of?ce at 495-7760 with policy questions prior to submitting this form. SSP America Matt?s Big Breakfast PHX Sky Harbor Airport Terminai 4 Date: 0ct01'14 Card Type: Amex Acct Card Entry: SWIPED Trans Type: PURCHASE Trans Key: 818002637726981 Auth Code: 580495 Check: 5068 Tabie: 54/1 Server: 413020 Daniei Subtotai: 11 . 32 Tip 93 Totai a? Ej?_ Signature Gratuity Not Inciuded I agree to pay above totai according to my card issuer agreement. Customer Copy EdlleHL QEHHS CHE INC Cab 3214 HHEK: 12519 i?f?ifiq TR 13? ETHET END HILES 21:41 32:31 13.? Fare: 34.25 Extra: 0.08 Toll: i ?.50 9.99 Tie: 8.38 58.35 Tare: AMER Card: 3018 RUTH: 561482 The Red House Restaurant 98 Winthrop St Cambridge, MA 02138 617?576?0605 Date: Oct01'14 Card Type: AMEX Acct Card Entry: SHIPED Trans Type: PURCHASE Auth Code: 588667 Check: 4899 Tabie: 2/1 Server: 4104 Red Hous Subtotai4'9 TOTAL :3 Si?: kf 3 SIGNATURE THIS IS YOUR copy Teresa Tenbrink 'om: Sent: Thursday, September 04, 2014 9:09 AM To: Teresa Tenbrink Subject: Your US Airways flight US AIRWAYS Your reservation 2331193?! T840 Erase?! ?12- You?itr Lozzirrn.r.t" II Ill Date issued: Thursday, September 04, 2014 Scan at any US Airways kiosk to check in 9 Next stop: the airport. See terminal information and ?nd your way. Confirmation code: US Airways Need a car? Get your wheels in Boston, MA Reserve your car now and earn Dividend Miles with Alamo and National. Need a hotel? Get a room in Boston. MA You're sure to get the best rates here. Book a hotel Passenger summary Passenger name Frequent flyer (Airline) Ticket number Special needs Susan Bittersmith - (US) 03723719372251 Redacted - Personal Information (602) 955- res?2:353:21; ttenbrink@azcc.gov Trip details 5 Download to Outlook HX 0 Phoenix, AZ to Boston, MA Wednesday, October 01,2014 507 Operated by US Airways DEPART 12:30 PM PHX Terminal 4 AIRCRAFT A320 (17. ARRIVE 08:24 PM 808 Terminal CABIN Coach TRAVEL TIME 4h 54m MEAL lvlarketPlaceTM SEATS B9. BOS Boston, MA to Phoenix, AZ Friday, October 03, 2014 629 Operated by US Airways DEPART 04:35 PM 808 Terminal AIRCRAFT A321 ARRIVE 07:12 PM PHX Terminal 4 CABIN Coach TRAVELTIME 5h37m MEAL IVIarketPlaceTM - SEATS LIMOS.COM memo I - Jar-??1 U25 ?t I ., Total travel cost (1 passengers) Your fare (Non?refundable) Adult PHX to BOS (KA14ZNJ3) $194.42 805 to PHX (KA14ZNJ3) $194.42 Taxes and fees $57.36 Subtotal Number of passengers Total by passenger type Total fare (All passengers) I-vCharged to Teresa Tenbrink (Visa) Helpful links Travel tools and tips Airport information US Airways Club Airport security Seated in an exit row? About 6090 Wi-Fi Bags Trip information Manage your reservation Join Dividend Miles TSA regulations $446.20 1 $446.20 $446.20 You paid $446.20 Change your seats Baggage policies Buy Gogo Wi-Fi Pay for your checked bags when you check in online or at the airport! Read more about bags. Carry ons" All flights Checked bags (each waylper person)? 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Send US your compliments andfor complaints. Federal law forbids the carriage of hazardous materials aboard aircraft in your luggage or on your person. A violation can result in five years' imprisonment and penalties of $250,000 or more (49 U.S.C. 5124). Hazardous materials include explosives, compressed gases, flammable liquids and solids, oxidizers, poisons. corrosives and radioactive materials. Examples: Paints, lighter fluid, fireworks, tear gases. oxygen bottles, and radio-pharmaceuticals. There are special exceptions for small quantities (up to 7'0 ounces total) of medicinal and toilet articles carried in your luggage and certain smoking materials carried on your person. Go to usairwayscomjhazmat for more info. LIE: ?inrtlay's, '1 ?1 '1 ?Iftl'. Flic- Salad-:- Te mpg, {'42 3:52:31 We are committed to protecting your privacy. Your information is kept private and confidential. or information about our privacy policy visit usairwayscorn. Please do not reply to this email, it is not monitored. If you'd like to contact us. please visit our Website From: To: Subject: Date: Susan Bitter Smith "Jo-Ann_Mahoney@hks.harvard.edu" Re: HEPG Dinner Choice: RSVP noon Wed Tuesday, September 30, 2014 1:49:25 PM Tenderloin please. Susan From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Tuesday, September 30, 2014 12:19 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: Susan Bitter Smith "Mahoney, Jo-Ann" RE: HEPG Renewable/Climate Panel Monday, September 29, 2014 11:12:00 AM Thanks, I have these and the articles - I will be ready.  Susan Susan Bitter Smith Commissioner Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625 -----Original Message----From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Monday, September 29, 2014 10:59 AM To: Susan Bitter Smith Subject: RE: HEPG Renewable/Climate Panel Hi Susan, Here are the bios for your panel.  We are just looking for a brief introduction of the speakers. Best, Jo-Ann -----Original Message----From: Susan Bitter Smith [mailto:SBitterSmith@azcc.gov] Sent: Thursday, September 25, 2014 4:46 PM To: Mahoney, Jo-Ann Subject: Re: HEPG Renewable/Climate Panel Thank you! ----- Original Message ----From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Thursday, September 25, 2014 10:23 AM To: Susan Bitter Smith Subject: RE: HEPG Renewable/Climate Panel Dear Susan, Thank you for agreeing to serve as the moderator of our Thursday afternoon session next week.  Ashley Brown's letter, attached, outlines your role.  We will be sending speaker bios 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: Subject: Date: Attachments: Mahoney, Jo-Ann Susan Bitter Smith RE: HEPG Renewable/Climate Panel Monday, September 29, 2014 10:58:43 AM Charles Frank.doc David Cash.docx Richard Schmalensee.doc Rob Gramlich.docx Hi Susan, Here are the bios for your panel.  We are just looking for a brief introduction of the speakers. Best, Jo-Ann -----Original Message----From: Susan Bitter Smith [mailto:SBitterSmith@azcc.gov] Sent: Thursday, September 25, 2014 4:46 PM To: Mahoney, Jo-Ann Subject: Re: HEPG Renewable/Climate Panel Thank you! ----- Original Message ----From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Thursday, September 25, 2014 10:23 AM To: Susan Bitter Smith Subject: RE: HEPG Renewable/Climate Panel Dear Susan, Thank you for agreeing to serve as the moderator of our Thursday afternoon session next week.  Ashley Brown's letter, attached, outlines your role.  We will be sending speaker bios 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 Charles R. Frank, Jr. Job History Present Positions. • Non-Resident Senior Fellow, Brookings Institution (from 2013). • Director, Central European Media Enterprises, a NASDAQ listed company (from 2001). • Advisory Committee Member, Sigma Bleyzer Growth Fund IV, Ukraine (from 2001). 2001 to 2013. • Chief Financial Officer, Central European Media Enterprises (2009-2010). • Board Member, Arcelor Mittal Steel Romania (2003-2013). • Investment Committee Member, Darby Central European Mezzanine Fund (2003-2013) • Board Member, Megafon, Russia (2008-2009). • Board Member, Romanian-American Enterprise Fund (2001-2008). 1997 to 2001. First Vice President and Acting President, European Bank for Reconstruction and Development. 1988 to 1997. GE Capital, Vice President and Managing Director, Structured Finance Group (SFG). 1978-87. Vice President, Salomon Brothers. 1974-1978. Deputy Assistant Secretary of State for Economic and Social Affairs and Chief Economist on Policy Planning Staff, U.S. Department of State. 1972-1974. Senior Fellow, Brookings Institution. 1967-1972. Professor of Economics and International Affairs and Director, Research Program in Economic Development, Princeton University. 1965-1967. Assistant Professor of Economics, Yale University. 1963-1965. Lecturer, Makerere University College, Kampala, Uganda. Education 1963. Ph.D., Princeton University, Economics. 1959. B.S., Rensselaer Polytechnic Institute, Major in Mathematics and Minor in Economics Who’s Who in America Who’s Who in the World Who’s Who in Economics Council on Foreign Relations International Who’s Who Honors 1996 Industry All Star Award, Independent Energy 1996 Project Financier of the Year, Infrastructure Finance Who’s Who in International Banking Writers Directory Advisory Boards Center for International Affairs, Princeton University, Advisory Board Member (1988-91). U.S. Agency for International Development, Research Advisory Board Member (1967-72). Korea Development Institute. Editorial Board Member (1969-74). Publications Author of many books and articles in the field of economic development, international trade and finance, mathematical economics, and operations research. Biography: Commissioner David W. Cash Governor Deval Patrick swears in MassDEP Commissioner David W. Cash David W. Cash was appointed on March 26, 2014 as Commissioner of the Massachusetts Department of Environmental Protection (MassDEP) by Governor Deval Patrick and his Secretary of Energy and Environmental Affairs, Richard K. Sullivan Jr. Dr. Cash brings to MassDEP a wealth of experience in environmental, energy and regulatory sectors. He most recently held the position of Commissioner at the Massachusetts Department of Public Utilities (DPU) where he helped lead efforts to modernize the grid, expand the deployment of energy efficiency and renewable energy, and empower customers in their energy decisions. Prior to his work at the DPU, Dr. Cash was the Undersecretary for Policy in the Massachusetts Executive Office of Energy and Environmental Affairs (EEA). In this role, Dr. Cash advised the EEA Secretary on an array of issues, including climate change, energy, land management, water management, oceans, wildlife and fisheries, air and water quality, environmental and energy dimensions of transportation, and waste management. He was one of the architects of clean energy legislation and implementation in the first term of the Patrick Administration, including the Green Communities Act, the Global Warming Solutions Act, the Green Jobs Act and the Clean Energy Biofuels Act. As part of this work, he led the Secretariat's effort in developing the Massachusetts Clean Energy and Climate Plan for 2020, which provides a roadmap of policies and programs that will lower energy costs, create clean energy jobs and reduce greenhouse gas emissions. Prior to working for the Commonwealth, Dr. Cash was a research associate at the John F. Kennedy School of Government at Harvard University, and a Lecturer in Environmental Science and Public Policy. He also taught science in the Amherst, Massachusetts public schools from 1990-1993. He received a Ph.D. in Public Policy from the Kennedy School at Harvard in 2001, and a B.S. in biology from Yale University in 1987. RICHARD SCHMALENSEE Richard Schmalensee is the Howard W. Johnson Professor of Economics and Management, Emeritus at MIT. He has served as a member of the MIT Energy Council and Director of the MIT Center for Energy and Environmental Policy Research. He served as the John C Head III Dean of the MIT Sloan School of Management from 1998 through 2007. He was the Member of the President's Council of Economic Advisers with primary responsibility for energy and environmental policy from 1989 through 1991. Professor Schmalensee has published 11 books and more than 120 articles; his work focuses on industrial organization economics and its policy applications. He was cochair of the MIT Energy Initiative study The Future of the Electric Grid and is currently co-chair of the ongoing study The Future of Solar Energy. He is a Fellow of the Econometric Society and the American Academy of Arts and Sciences, a Director of the National Bureau of Economic Research, and Board Chair-Elect of Resources for the Future. ROB GRAMLICH Rob Gramlich is Senior Vice President for Government and Public Affairs at the American Wind Energy Association, the national trade association of over 1000 entities involved in all aspects of wind energy production, based in Washington DC. Rob joined AWEA in 2005 and oversees the organization’s federal and state legislative, regulatory, research, and public affairs functions. He has testified before the US Congress, Federal Energy Regulatory Commission (FERC) and state regulatory commissions, and has served on the U.S. Department of Energy's Electricity Advisory Committee. He has published articles on wind integration, wind markets and policy, economic incentives for environmental protection, power market regulation, and electricity market design. Rob served as Economic Advisor to FERC Chairman Pat Wood III and Senior Economist for PJM Interconnection, and worked for PG&E National Energy Group, World Resources Institute, and the Lawrence Berkeley National Laboratory in the 1990s. Rob has a Master’s degree in Public Policy from UC Berkeley and a BA with honors and distinction in economics from Colby College. From: To: Subject: Date: Teresa Tenbrink "Mahoney, Jo-Ann" RE: Harvard Kennedy School Paulson Forum Monday, September 29, 2014 9:07:00 AM Good morning,   Commissioner Bitter Smith is disappointed to miss this event but her flight arrives around 8pm on Wednesday, October 1st.   Thanks for the invitation!   Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Monday, September 29, 2014 7:51 AM To: Mahoney, Jo-Ann Subject: Harvard Kennedy School Paulson Forum   Dear HEPG Participants,   For those of you interested in attending Wednesday evening’s Forum event, Henry Paulson will be speaking in the Kennedy School Forum from 6:00-7:00 pm.  The Forum is an open space and this event is not ticketed.   We recommend arriving early (5:30-5:45) to garner a seat on the main floor.  The Forum can be accessed through the main door at 79 JFK Street.     China, Climate Change and Financial Risk: Crisis Management in a Global Context A conversation with HENRY M. PAULSON, Jr. Chairman of The Paulson Institute; Secretary of the Treasury (2006-2009); CEO of Goldman Sachs (1999-2006)   JFK Jr. Forum, Harvard Kennedy School   October 1, 2014 6-7pm     Best, Jo-Ann (617) 495-1390 From: To: Subject: Date: Susan Bitter Smith "Jo-Ann_Mahoney@hks.harvard.edu" Re: HEPG Renewable/Climate Panel Thursday, September 25, 2014 1:46:10 PM Thank you! ----- Original Message ----From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Thursday, September 25, 2014 10:23 AM To: Susan Bitter Smith Subject: RE: HEPG Renewable/Climate Panel Dear Susan, Thank you for agreeing to serve as the moderator of our Thursday afternoon session next week.  Ashley Brown's letter, attached, outlines your role.  We will be sending speaker bios 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: Subject: Date: Susan Bitter Smith "ashley_brown@harvard.edu" Re: HEPG Renewable/Climate Panel Wednesday, September 24, 2014 3:05:46 PM Sounds good! ----- Original Message ----From: ashley_brown@harvard.edu [mailto:ashley_brown@harvard.edu] Sent: Wednesday, September 24, 2014 03:03 PM To: Susan Bitter Smith Subject: Re: HEPG Renewable/Climate Panel We can go over them Thursday morning Sent via BlackBerry from T-Mobile -----Original Message----From: Susan Bitter Smith Date: Wed, 24 Sep 2014 15:01:21 To: 'ashley_brown@harvard.edu' Subject: Re: HEPG Renewable/Climate Panel That would be helpful so I don"t screw it up!  Susan ----- Original Message ----From: ashley_brown@harvard.edu [mailto:ashley_brown@harvard.edu] Sent: Wednesday, September 24, 2014 02:38 PM To: Susan Bitter Smith Cc: Bill HOGAN ; Jo-Ann MAHONEY Subject: HEPG Renewable/Climate Panel Thanks Susan. Let me know of you want to go over the ground rules ------Original Message-----From: Susan Bitter Smith To: Ashley BROWN Subject: Sent: Sep 24, 2014 5:34 PM Ashley- happy to help moderate!  Susan Sent via BlackBerry from T-Mobile From: To: Subject: Date: Susan Bitter Smith "Jo-Ann_Mahoney@hks.harvard.edu" Re: HEPG October Meeting Wednesday, September 17, 2014 1:57:32 PM I will be at the dinner and the reception! I am interested in attending the Paulson presentation but not sure if my plane gets in at a time that works for that. Do you have the details? Thanks. Susan From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Wednesday, September 17, 2014 01:06 PM To: Mahoney, Jo-Ann Subject: HEPG October Meeting We look forward to your participation in the upcoming Harvard Electricity Policy Group meeting, to be held on October 2-3, at the Harvard Kennedy School.  The sessions will take place on the fifth floor of our Taubman Building, located on Eliot Street adjacent to the Charles Hotel.   We will hold the conference reception and dinner on Thursday evening at Chef Jody Adams’ Rialto Restaurant, a Harvard Square institution, located in the Charles Hotel.  You are welcome to bring a guest who is travelling with you.  Kindly RSVP  by Sept. 25.   We have learned that the Kennedy School Forum will host a talk by Henry Paulson on Wednesday evening, October 1.  If you will be in town and would like further information, please contact me.   Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 Jo-ann_mahoney@hks.harvard.edu     From: To: Subject: Date: Susan Bitter Smith Teresa Tenbrink Re: HEPG October Meeting Wednesday, September 17, 2014 1:48:00 PM Yes please RSVP - just me! From: Teresa Tenbrink Sent: Wednesday, September 17, 2014 01:22 PM To: Susan Bitter Smith Subject: FW: HEPG October Meeting Would you like to go to the conference reception?  I’ll ask what time it is.   Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Wednesday, September 17, 2014 1:07 PM To: Mahoney, Jo-Ann Subject: HEPG October Meeting   We look forward to your participation in the upcoming Harvard Electricity Policy Group meeting, to be held on October 2-3, at the Harvard Kennedy School.  The sessions will take place on the fifth floor of our Taubman Building, located on Eliot Street adjacent to the Charles Hotel.   We will hold the conference reception and dinner on Thursday evening at Chef Jody Adams’ Rialto Restaurant, a Harvard Square institution, located in the Charles Hotel.  You are welcome to bring a guest who is travelling with you.  Kindly RSVP  by Sept. 25.   We have learned that the Kennedy School Forum will host a talk by Henry Paulson on Wednesday evening, October 1.  If you will be in town and would like further information, please contact me.   Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School/Harvard University 79 JFK Street Cambridge, MA 02138 Jo-ann_mahoney@hks.harvard.edu     From: To: Subject: Date: Susan Bitter Smith Teresa Tenbrink Re: Commissioners Registration; Invitation to Next HEPG Meeting Logistics/Hotel Deadline Tuesday, August 05, 2014 11:03:25 AM No it starts the morning of the 2nd in Boston so I will have to go in the night before. I need a room on the 1st and 2nd. From: Teresa Tenbrink Sent: Tuesday, August 05, 2014 11:00 AM To: Susan Bitter Smith Subject: RE: Commissioners Registration; Invitation to Next HEPG Meeting Logistics/Hotel Deadline Do you think you’ll just stay overnight on Oct. 2?   Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   From: Susan Bitter Smith Sent: Tuesday, August 05, 2014 10:44 AM To: Teresa Tenbrink Subject: Re: Commissioners Registration; Invitation to Next HEPG Meeting Logistics/Hotel Deadline   I did not- would you ? From: Teresa Tenbrink Sent: Tuesday, August 05, 2014 10:19 AM To: Susan Bitter Smith Subject: RE: Commissioners Registration; Invitation to Next HEPG Meeting Logistics/Hotel Deadline Done.  Did you let them know that you would like to stay at the Harvard Square hotel?   Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   From: Susan Bitter Smith Sent: Tuesday, August 05, 2014 9:17 AM To: Teresa Tenbrink Subject: Fw: Commissioners Registration; Invitation to Next HEPG Meeting Logistics/Hotel Deadline   Teresa I do want to attend. Would you fill out the attached and return? Thanks. Susan From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Tuesday, August 05, 2014 09:12 AM To: Mahoney, Jo-Ann Subject: Commissioners Registration; Invitation to Next HEPG Meeting Logistics/Hotel Deadline Dear Commissioner,   We would like to invite you to attend the next session of the Harvard Electricity Policy Group, especially as we intend to dedicate one of our discussion sessions to state and federal responsibility for 111(d).  The meeting will take place in Cambridge at the Harvard Kennedy School on ThursdayFriday, October 2-3, 2014.  We also plan to consider renewables and carbon policy; and a third topic to be announced, and will send out panel descriptions and an agenda shortly.   For your planning purposes, the meeting will convene at 8:30 am on Thursday, October 2 and adjourn at noon on Friday the 3rd, and we will host a conference reception and dinner on Thursday evening.   If you should need travel assistance, we are prepared to offer you lodging in the Cambridge area and to cover the cost of your ground and air transportation, which we will reimburse .  If you would like to attend this meeting, kindly let me know by August 26, so that we might secure lodging prior to our hotel deadlines.  Also, kindly return the registration form to my attention.   We hope that you can be with us in October and wish you the best for the remainder of the summer.   Best regards, Jo-Ann   Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School 79 JFK Street Cambridge, MA 02138 617-495-1390   From: To: Subject: Date: Susan Bitter Smith "Jo-Ann_Mahoney@hks.harvard.edu" Re: Commissioners Registration; Invitation to Next HEPG Meeting Logistics/Hotel Deadline Tuesday, August 05, 2014 9:21:43 AM Jo Ann- thanks- I plan to attend and will get the form back to you! Susan From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Tuesday, August 05, 2014 09:12 AM To: Mahoney, Jo-Ann Subject: Commissioners Registration; Invitation to Next HEPG Meeting Logistics/Hotel Deadline Dear Commissioner,   We would like to invite you to attend the next session of the Harvard Electricity Policy Group, especially as we intend to dedicate one of our discussion sessions to state and federal responsibility for 111(d).  The meeting will take place in Cambridge at the Harvard Kennedy School on ThursdayFriday, October 2-3, 2014.  We also plan to consider renewables and carbon policy; and a third topic to be announced, and will send out panel descriptions and an agenda shortly.   For your planning purposes, the meeting will convene at 8:30 am on Thursday, October 2 and adjourn at noon on Friday the 3rd, and we will host a conference reception and dinner on Thursday evening.   If you should need travel assistance, we are prepared to offer you lodging in the Cambridge area and to cover the cost of your ground and air transportation, which we will reimburse .  If you would like to attend this meeting, kindly let me know by August 26, so that we might secure lodging prior to our hotel deadlines.  Also, kindly return the registration form to my attention.   We hope that you can be with us in October and wish you the best for the remainder of the summer.   Best regards, Jo-Ann   Jo-Ann Mahoney Project Director, Harvard Electricity Policy Group Harvard Kennedy School 79 JFK Street Cambridge, MA 02138 617-495-1390   From: To: Subject: Date: Susan Bitter Smith Teresa Tenbrink Re: Reimbursement for last week"s HEPG session Wednesday, June 18, 2014 3:18:12 PM Sure. From: Teresa Tenbrink Sent: Wednesday, June 18, 2014 03:15 PM To: Susan Bitter Smith Subject: RE: Reimbursement for last week's HEPG session Do you remember when you went to HEPG in Santa Monica?  Peter asked that we request HEPG to reimburse you for all the expenses.  Then you wrote a check for the amount that needed to go to the Commission.  Are you okay with doing that again?  I will submit it today and you can write a check once we receive the HEPG check.  It would be for $606.00 to the State of Arizona.    Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   From: Susan Bitter Smith Sent: Tuesday, June 17, 2014 8:39 AM To: Teresa Tenbrink Subject: Fw: Reimbursement for last week's HEPG session   From: Bostian, Trudi [mailto:Trudi_Bostian@hks.harvard.edu] Sent: Tuesday, June 17, 2014 08:15 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   From: To: Subject: Date: Attachments: Susan Bitter Smith Teresa Tenbrink Fw: Reimbursement for last week"s HEPG session Tuesday, June 17, 2014 8:39:11 AM universal_expense_form.pdf missing_receipt.pdf From: Bostian, Trudi [mailto:Trudi_Bostian@hks.harvard.edu] Sent: Tuesday, June 17, 2014 08:15 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: 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: 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: Attachments: Susan Bitter Smith Teresa Tenbrink Fw: HEPG Agenda Monday, June 09, 2014 9:14:50 AM Agenda_June2014.pdf From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Monday, June 09, 2014 08:57 AM To: Mahoney, Jo-Ann Subject: HEPG Agenda   HARVARD ELECTRICITY POLICY GROUP HARVARD ELECTRICITY POLICY GROUP SEVENTY-FIFTH PLENARY SESSION Harvard Kennedy School Cambridge, Massachusetts THURSDAY AND FRIDAY, JUNE 12-13, 2014 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? Moderator: Ashley Brown, Harvard Electricity Policy Group 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 6:15 pm Reception and Dinner Meritage Restaurant, Boston Harbor Hotel (Bus will load at 6:15pm outside the Charles Hotel) 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? Moderator: Mark Christie, Virginia State Corporation Commission 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: Susan Bitter Smith Teresa Tenbrink Fw: HEPG Logistics Monday, June 09, 2014 8:57:15 AM From: Mahoney, Jo-Ann [mailto:Jo-Ann_Mahoney@hks.harvard.edu] Sent: Monday, June 09, 2014 08:54 AM To: Mahoney, Jo-Ann Subject: HEPG Logistics 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: Subject: Date: Susan Bitter Smith "trudi_bostian@hks.harvard.edu" Re: Invitation to HEPG Dinner, RSVP Tuesday, May 27, 2014 8:17:36 AM Trudi I plan on attending- it is just me! Susan From: Bostian, Trudi [mailto:Trudi_Bostian@hks.harvard.edu] Sent: Tuesday, May 27, 2014 07:53 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: Mahoney, Jo-Ann Mahoney, Jo-Ann HEPG Agenda Thursday, May 08, 2014 9:40:34 AM Draft_Agenda_June2014.docx 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: Attachments: Bostian, Trudi Susan Bitter Smith; Teresa Tenbrink Invitation to HEPG 75th Plenary Session, June 12-13, 2014, Cambridge MA Tuesday, April 15, 2014 8:01:38 AM Registration_form_6-14_comm.docx Dear Commissioner Bitter Smith,   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: Bostian, Trudi Teresa Tenbrink RE: HEPG Reimbursements Monday, March 17, 2014 9:32:04 AM Hi Teresa,   This should be fine.  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: Teresa Tenbrink [mailto:ttenbrink@azcc.gov] Sent: Friday, March 14, 2014 2:47 PM To: Bostian, Trudi Subject: RE: HEPG Reimbursements   Hi Trudi,   Attached is another reimbursement for Commissioner Susan Bitter Smith.  I have included the necessary receipts.  We are submitting her airfare this way instead of through the State.  Please let me know if you need anything else.   Thanks,   Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   From: Bostian, Trudi [mailto:Trudi_Bostian@hks.harvard.edu] Sent: Wednesday, March 12, 2014 7:54 AM To: Teresa Tenbrink Subject: RE: HEPG Reimbursements   Hi Teresa,   Please redo the one for the State of Arizona.  The UEF form is only for individuals.  For the state, I will need an invoice, which is a letter on official stationery itemizing the expenses, and where and to whom the check should be sent.   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: Teresa Tenbrink [mailto:ttenbrink@azcc.gov] Sent: Tuesday, March 11, 2014 4:00 PM To: Bostian, Trudi Subject: HEPG Reimbursements   Hi Trudi,   Please find attached two reimbursements for Commissioner Susan Bitter Smith.  One is for her personally and the other is for the State of Arizona.  I have attached the necessary receipts.  Please let me know if you have any questions.   Thanks!   Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   ========================================== This footnote confirms that this email message has been scanned to detect malicious content. If you experience problems, please e-mail postmaster@azcc.gov ========================================== ========================================== 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: Teresa Tenbrink "Bostian, Trudi" RE: HEPG Reimbursements Friday, March 14, 2014 11:47:00 AM SBS Reimbursement.pdf Hi Trudi,   Attached is another reimbursement for Commissioner Susan Bitter Smith.  I have included the necessary receipts.  We are submitting her airfare this way instead of through the State.  Please let me know if you need anything else.   Thanks,   Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   From: Bostian, Trudi [mailto:Trudi_Bostian@hks.harvard.edu] Sent: Wednesday, March 12, 2014 7:54 AM To: Teresa Tenbrink Subject: RE: HEPG Reimbursements   Hi Teresa,   Please redo the one for the State of Arizona.  The UEF form is only for individuals.  For the state, I will need an invoice, which is a letter on official stationery itemizing the expenses, and where and to whom the check should be sent.   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: Teresa Tenbrink [mailto:ttenbrink@azcc.gov] Sent: Tuesday, March 11, 2014 4:00 PM To: Bostian, Trudi Subject: HEPG Reimbursements   Hi Trudi,   Please find attached two reimbursements for Commissioner Susan Bitter Smith.  One is for her personally and the other is for the State of Arizona.  I have attached the necessary receipts.  Please let me know if you have any questions.   Thanks!   Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   ========================================== This footnote confirms that this email message has been scanned to detect malicious content. If you experience problems, please e-mail postmaster@azcc.gov ========================================== HARVARD UNIVERSITY UNIVERSAL EXPENSE FORM EMPLOYEE TYPE 0R AFFILIATION PAYMENT TYPE (Cum om ONE) Harvard Employee Out of Pocket El Af?liate/Harvard StudentICasual/Stipend - complete shaded areas CI American Express Corporate Card Invited Guest/manor - complete shaded areas Reimbursement Method (Check only one) El Direct Deposit El Paper Check Date: Reimbursee or Cardholder Name: Web VoucherIPO#: Elm/[Ll SUQM Sm?l?k Social Secl'l'ax lD#: Harvard 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: Redacted Personal Information BUSINESS PURPOSE (Detailed reason for expenditure. For travel or entertainment. Include person andlor organization visited and location. Also include expense date range. List additional business purposes on page 2.) Date 3} of emensels) #1 1'29,? ?ml 9* (Winner #2 2?;qu Parlor/re. WM ?40 L-A. ?lo WM JAEQILL #3 #4 #5 SUMMARY OF EXPENSES (Room for additional expenses is available on page 2) . . . . Business Business Air/Rail Ground . Purpose# (date, detail, Travel Trans. Meals Other 2!?qu Dinner 8222 :1 ale/M Perla/e. to L-A. Subtotals from page 2. if applicable: 23,0 52 .23 2 El .Zg Less ADVANCES EXPENSE REPORT TOTAL: 2230.? 282 .25 TOTAL AMOUNT OF RECEIPTS UNDER $75 $52 28' that th_e__se are all legitimate Harvard University business expenses. SIGNATURE: Ll/M?gh 413/ X33 Date: Reimbursee Permanent Legal Addres Reimbursee Check Mailing Address. if different than Legal: . R111 Ak 1200 U). ihl??tm 1? Mil, AZ 1 have reviewed these expenses and all are in accordance with University ub policy. m} Preparer: Phone: __Approver: (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 ?nancial of?ce requires this information for processing purposes. This information will be in the Web Voucher Amount Tub (3) Org (5) Object (4) Fund (6) Activity (6) Sub (4) Root (5) Business ADDITIONAL BUSINESS PURPOSES OR INFORMATION 3 of #6 #7 #8 #9 ADDITIONAL EXPENSES Business Description Air/Rail Ground date detail etc. Travel Trans Business Meals Other Total Lodging Subtotals, carry to first sheet Hints and policy notes: 1. 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. 2. Please refer to the Policy at a Glance or the complete travel policy at 3 To expedite processing, contact the Travel Of?ce at 495-7760 with policy questions prior to submitting this form. Teresa Tenbrink From: Sent: To: Subject: Thursday, February 06, 2014 1:04 PM Teresa Tenbrink Your US Airways flight US A I RWAYS Your reservation Book lravel Travel loois Diwdend Miles Specials US Airways Vacations You're confirmed Date issued: Thursday, February 06, 2014 0 Next stop: the airport. See terminal information and find your way. Confirmation code: GHK59J II US Airways Need a car? Get your wheels in Los Angeles, CA Reserve your car now and earn Dividend Miles with Alamo and National. Need a hotel? Get a room in Los Angeles, CA You're sure to get the best rates here. Passenger summary Passenger name Frequent ?yer (Airline) Ticket number Scan at any US Airways kiosk to check in Reserve now Book a hotel Special needs Susanbitter Smith 03723453479620 Redacted Personal information Day of departure phone. (480) 267- Email for receipt. ttenbrink@azcc.gov Trip details vi Download to Outlook HX LAX Phoenix, A2 to Los Angeles, CA Wednesday, February 26, 2014 509 Operated by US Airways 07:45 PM PHX A319 55:. 08:11 PM LAX Coach 1h 26m -- LAX Er?iy?igiilerj?fgtg AZ 486 Operated by US Airways DEPART 04:20 PM LAX AIRCRAFT A321 aria ARRIVE 06:42 PM PHX CABIN Coach TRAVEL TIME 1h 22m MEAL -- SEATS LIMOS.COM - ?Ii. Pu; 11:? A ("?113 $10 off Eam Miles BOOK 0 4? Total travel cost (1 passengers) Your fare (Non-refundable) Adult PHX to LAX (GXAUNL2) $111.63 LAX to PHX (KXAVNL2) $81.86 Taxes and fees $36.51 Subtotal $230.00 Number of passengers 1 Total by passenger type $230.00 Total fare (All passengers) $230.00 L+Charged to Teresa Tenbrink You paid $23030 (Visa) Helpful links Travel tools and tips Trip information Aimort information US Ainrvays Club Manage your reservation Change your seats Airport security ?eated in an exit row? Join Dividend Miles Baggage golicies About Gogo Wi-Fi regulations Buy Gogo Wi-Fl Bags Pay for your checked bags when you check in online or at the airport! Read more about bags. Carry ons* Carry-on bag Personal item All flights a a Checked bags (each way/per person)* 15! bag 2nd bag US. Canada Latin America Caribbean Bermuda South America (except Brazil) Transatlantic a ?Carry-ons can inches (cm). A personal item is a handbag. briefcase or laptop bag. ?1st 2nd checked bags can be up to 50 and 62 inches except Brazil where you're allowed up to 70 lbs. Europe fees apply for travel toffrom Asia through Europe. Baggage fees are non-refundable. Transpacific ll Brazil (except Hawaii) 1st, 2nd and 3rd checked bag fees waived Gold. 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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. 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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. 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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. 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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. 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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: Brown, Ashley Susan Bitter Smith RE: Thank you Monday, March 03, 2014 12:20:26 PM Thanks Susan. It was great having you with us. I look forward to seeing you again soon.   From: Susan Bitter Smith [mailto:SBitterSmith@azcc.gov] Sent: Monday, March 03, 2014 1:50 PM To: Brown, Ashley Subject: Thank you   Ashley, once again thank you for hosting me at the Harvard Electricity Policy Group meeting.  I again learned a lot and as you might expect, especially enjoyed the DG panel. Looking forward to seeing you again soon.  Susan   Susan Bitter Smith Commissioner Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   ========================================== 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: Subject: Date: Attachments: Bostian, Trudi Hannes Pfeifenberger"s slides Thursday, February 27, 2014 1:36:56 PM Pfeifenberger.pdf Hello, Please find these attached.  Thank you. Trudi Bostian Staff Assistant Harvard Electricity Policy Group 79 John F. Kennedy Street Mailbox 84 Cambridge, MA 02138 Ph: 617-496-6760 E: trudi_bostian@hks.harvard.edu Energy and Capacity Markets: Tradeoffs in Reliability, Costs, and Risks Presented to Harvard Electricity Policy Group Sev enty-Fourth Pl enary Session Prepared by Johannes P. Pfeifenberger Samuel A. Newell Kathleen Spees February 27, 2014 Copyright © 2014 The Brattle Group, Inc. Content I. When might we need a capacity market? (Or do we really?) II. Implications of ERCOT Report: Reliability, cost, and risk tradeoffs between energy-only and capacity markets III. Highlights from FERC Report: Impacts of interties, price caps, DR IV. Things to think about before implementing a capacity market V. Policy implications Appendix A: Additional FERC Study Results Appendix B: Characteristics of Successful Capacity Markets (Additional Detail) Appendix C: Additional Reading, Author Contacts, About Brattle This presentation is based on the following two reports: ▀ ▀ Newell, Spees, Pfeifenberger, Karkatsouli, Wintermantel, and Carden, Estimating the Economically Optimal Reserve Margin in ERCOT, Report prepared for The Public Utility Commission of Texas, The Brattle Group, January 31, 2014. Pfeifenberger, Spees, Carden, and Wintermantel, Resource Adequacy Requirements: Reliability and Economic Implications, Prepared for the Federal Energy Regulatory Commission (FERC), The Brattle Group, September 2013. 1 brattle.com I. When Might We Need Capacity Markets?   Reserve-margin mandates (and the capacity market created by them) are generally called for when energy-only markets do not attract “adequate” investments: ▀ Energy market designs that lead to price suppression? − − − − ▀ ▀ ▀ Low price caps and inadequate scarcity pricing? Poor integration of demand-response resources? Substantial locational differences not reflected in market prices? Operational actions (e.g., dispatch of emergency resources) that depress clearing prices? Challenging investment risks (e.g., in hydro-dominated markets)? Distortions created by out-of-market payments for some resources that lead to over-supply or high costs? Incomplete or poorly-designed ancillary service markets? − Missing ramping products? − Not co-optimized with energy market? − Operational actions that depress clearing prices? ▀ Most Likely: Resource adequacy preferences (e.g., 1-in-10) higher than what even fully-efficient energy and A/S markets would provide brattle.com 2 II. Summary of Recent ERCOT Report ▀ ▀ The PUCT asked us to estimate the economically-optimal reserve margin in ERCOT to inform their ongoing review of market design for resource adequacy. Under base case assumptions, we estimate reserve margins of: − 10.2% economic optimum − 11.5% in equilibrium of current energy market design (minimizes customer cost) − 14.1% required to meet 1-in-10 reliability standard ▀ Enforcing a 1-in-10 reserve margin requirement at 14.1% (with or without a centralized capacity market) would increase long-run average customer costs by approximately 1% of retail rates relative to the 11.5% energy-only market in equilibrium : − Considered only energy and capacity price impacts − Potential additional benefits: risk mitigation, DR integration − Potential additional costs: implementation, added complexity, disputes 3 brattle.com II. Modeling Approach − Demand in ERCOT and external regions − Generation with randomized outages − Demand response of several types with differing availability and emergency or economic triggers − Emergency procedures that ERCOT triggers in shortage conditions ▀ ▀ Load Duration Curves Modeled Implemented study with SERVM, a probabilistic multi-area reliability and economic modeling tool, representing: Monte Carlo simulation of 7,500 full annual (hourly-sequential) simulations at each reserve margin Primary outputs reported at each reserve margin include: − Reliability metrics (LOLE, LOLH, EUE) − Economic costs (production costs, DR curtailment costs, emergency intervention costs) − Market results (prices, energy margins) (Peak Hours, Before DR Gross-Up or Forecast Error) 110% 105% Peak Load (% of 50/50 Peak) ▀ 100% Weather-Normal Peak Load 2011 Weather 95% Weather-Normal Year 90% 85% 0 50 100 150 Hour of Year 200 4 brattle.com 250 II. Reliability-Based Reserve Margin Targets ▀ We estimated that a 14.1% reserve margin would be required to meet the traditional 1in-10 loss of load event (LOLE) standard; − At 11.5%, average LOLE is three times higher (with average MWh shed 25% higher) ▀ Results sensitive to: − Forward period at which supply decisions are locked in, and consequential load forecast error (LFE) that needs to be considered in analysis (removing LFE drops the reserve margin to 12.6%) − Likelihood of extreme 2011 weather recurring treated at 1% chance in base case (raising it to 1/15 or equal chance would increase the reserve margin to 16.1%) 5 brattle.com II. Economically Optimal Reserve Margin Total System Costs across Planning Reserve Margins Firm Load Shedding (risk neutral) Regulation Shortages $36,000 Non-Spinning Reserve Shortages Spinning Reserve Shortages Price-Responsive Demand TDSP Load Management Non-Controllable LRs 30-Minute ERS 10-Minute ERS Emergency Generation External System Costs (Above Baseline) Production Costs (Above $10B/Yr Baseline) Marginal CC Capital Costs Economically Optimal Reserve Margin at 10.2% Total System Costs ($Million/Year) $35,800 $35,600 $35,400 $35,200 $35,000 17.5% 16.5% 15.6% 14.6% 13.7% 12.7% 11.8% 10.8% 9.8% 8.9% 7.9% 7.0% 6.0% $34,800 ERCOT Reserve Margin (% ICAP) Notes: Total system costs include a large baseline of total system costs that do not change across reserve margins, including $15.2 B/year in transmission and distribution, $9.6 B/year in fixed costs for generators other than the marginal unit, and $10B/year in production costs. brattle.com 6 II. Energy-Only Market Equilibrium ▀ Risk neutral, equilibrium reserve margin determined by market forces, where supplier energy margins equal the gross Cost of New Entry (CONE) Current ERCOT market design results in 11.5% equilibrium reserve margin for base case (913% for sensitivity cases) − Equilibrium exceeds economic optimum because administrative scarcity prices exceed marginal costs in some cases ▀ Significantly greater uncertainty of actual outcomes CC Energy Margins $350 Base Case 0.1 LOLE Base Case Optimal RM $300 CC Energy Margins ($/kW-yr) ▀ $250 Base Case $200 $150 CC CONE $100 Energy-only equilibrium RM is higher than optimum because prices sometimes exceed marginal cost $50 $0 7% 9% 11% 13% 15% 7 brattle.com 17% II. Equilibrium Capacity Market Prices Capacity is valuable for reserve margin requirements above the 11.5% energy-only equilibrium − Equilibrium capacity price set by the market at Net CONE (gross CONE minus energy margins) − 1-in-10 reliability at 14.1% requires average capacity price of $40/kW-yr ($30-$60/kW-y in sensitivity cases) ▀ Even at lower levels, a reserve margin mandate will prevent very low reserve margin outcomes, mitigate some boom-bust cycles, and make capacity more valuable than in equilibrium Equilibrium Capacity Prices at different Reserve Margin Requirements $140 Equilibrium Capacity Price ($/kW-y) ▀ Base Case Optimal RM $120 0.1 LOLE CC CONE $100 CC Energy Margins $80 $60 $40 Equilibrium Capacity Price $20 Net CONE = CONE - Energy Margins $0 7% 9% 11% 13% Reserve Margin (% ICAP) 15% 8 brattle.com 17% II. Volatility in Spot Prices and Energy Margins Load-Weighted Spot Energy Price $200 Energy-Only Equilibrium Energy Price ($/MWh) $160 $120 $100 $80 Average $60 $40 5th Percentile Median $250 $200 CC CONE $100 $0 9% 11% 12% 13% 14% 15% 17% Average $150 $0 8% 75th Percentile $300 $50 Reserve Margin (% ICAP) ▀ $350 $20 7% 95th Percentile 90th Percentile $400 95th Percentile 90th Percentile 75th Percentile $140 Energy-Only Equilibrium $450 CC Energy Margin ($/kW-yr) $180 Unhedged CC Energy Margins $500 5th Percentile 7% 8% Median 9% 11% 12% 13% 14% 15% 17% Reserve Margin (% ICAP) At 11.5% the average annual energy price is 20% higher than at 14%; average of top 10% of annual prices (unhedged) is 50% higher. Median prices significantly below average. 9 brattle.com II. Supplier Net Revenues ▀ ▀ Total supplier net revenues must reach CONE (on a long-run average basis) to attract new entry At higher reserve margin mandates, the source of revenues shifts from energy to capacity market (capacity makes up 32% of net revenues at 1-in-10) Volatility in supplier net revenues is reduced at higher reserve margins (but much of it can also be achieved through hedging) Supplier Net Revenues On Average and in the Top 10% of Years $800 Infeasible Equilibria Increasing Capacity Payments Associated with Progressively Higher Administratively -Set Reserve Margins Supplier Net Revenues Exceed Investment Costs $700 Supplier Net Revenues ($/kW-y) ▀ $600 Energy-Only Equilibrium 11.5% RM $500 $400 Top 10% of Years Unhedged $300 Top 10% of Years 80% Hedged $200 CC CONE Capacity Payments Long-Run Capacity Price Needed to Sustain Reserve Margin $100 Energy Margins $0 7.9% 8.9% 9.8% 10.8% 11.8% 12.7% 13.7% 14.6% 15.6% 17.5% Reserve Margin (ICAP %) 10 brattle.com II. Total Customer Costs ▀ ▀ ERCOT customer costs are minimized at the energy-only equilibrium and increase if higher reserve margin mandates are imposed A 14.1% reserve margin mandate (at 1-in-10) would increase customer costs by approximately $400 mil/year or 1% in long-run equilibrium The near-term difference between energy-only and capacity markets is more substantial because energy prices are currently below equilibrium levels (excess capacity relative to energyonly equilibrium) Total Customer Costs On Average and in the Top 10% of Years 25¢ Infeasible Equilibria Increasing Capacity Payments Supplier Net Revenues Associated with Progressively Higher Exceed Investment Costs Administratively-Set Reserve Margins 20¢ Energy-Only Equilibrium 11.5% RM Customer Costs (¢/kWh) ▀ 15¢ Top 10% of Years Unhedged Top 10% of Years 80% Hedged 10¢ Energy Capacity 5¢ Transmission and Distribution 0¢ 7.9% 8.9% 9.8% 10.8% 11.8% 12.7% 13.7% 14.6% 15.6% 17.5% Reserve Margin (ICAP %) 11 brattle.com II. Summary of Results from ERCOT Report Energy-Only Market Base Case Sensitivity Cases Equilibrium Reserve Margin (%) Realized Reliability Loss of Load Events Loss of Load Hours Normalized EUE (events/yr) (hours/yr) (% of MWh) Economics in Average Year Energy Price Capacity Price Supplier Net Revenue Average Customer Cost Total Customer Costs ($/MWh) ($/kW-yr) ($/kW-yr) (¢/kWh) ($B/Yr) $58 $0 $122 10.1¢ $35.7 Economics in Top 10% of Years Energy Price Capacity Price Supplier Net Revenue (Unhedged) Supplier Net Revenue (80% Hedged) Average Customer Cost (Unhedged) Average Customer Cost (80% Hedged) Total Customer Costs (Unhedged) Total Customer Costs (80% Hedged) ($/MWh) ($/kW-yr) ($/kW-yr) ($/kW-yr) (¢/kWh) (¢/kWh) ($B/Yr) ($B/Yr) $99 $0 $362 $244 15.1¢ 12.6¢ $53.6 $44.7 11.5% 9.3%-12.9% Capacity Market at 1-in-10 Base Case Sensitivity Cases 14.1% 12.6% - 16.1% 0.10 0.23 0.0001% 0.10 - 0.10 0.22 - 0.23 0.00008% - 0.0001% $58 - $60 $0 - $0 $97 - $122 10.1¢ - 10.7¢ $35.7 - $37.8 $48 $39 $122 10.2¢ $36.1 $46 - $53 $30 - $60 $97 - $122 10.2¢ - 10.8¢ $36.0 - $38.3 $95 - $102 $0 - $0 $173 - $444 $119 - $259 13.4¢ - 23.0¢ 9.8¢ - 21.8¢ $37.4 - $81.5 $34.6 - $77.2 $65 $76 $249 $193 12.9¢ 11.7¢ $45.7 $41.5 $58 - $77 $30 - $116 $152 - $302 $128 - $289 12.4¢ - 17.9¢ 10.2¢ - 17.7¢ $43.9 - $63.3 $36.2 - $62.9 0.33 0.27 - 0.85 0.86 0.68 - 2.37 0.0004% 0.0003% - 0.0013% 12 brattle.com III. FERC Study of Resource Adequacy ▀ Scope of September 2013 Study (released by FERC in Feb 2014): − Assessed economic/reliability implications of different resource adequacy standards. − Examine the widely-used one-day-in-ten-years (1-in-10) loss of load standard and compare it to alternative approaches to defining resource adequacy − Evaluate the implications of different resource adequacy standards from a customer cost, societal cost, risk mitigation, market structure, and market design perspective. ▀ Documented wide differences in application of 1-in-10 standard − 0.1 loss of load events (LOLE) per year interpretation is most widely used − 2.4 loss of load hours (LOLH) per year, economic reserve margins, and normalized expected unserved energy (EUE) also applied ▀ Even different applications of 0.1 LOLE standard and calculation of reserve margin have up to 5 percentage point impact on planning reserve margin − Different definition of “event” (e.g., load shed vs. operating reserve depletion) − Reserve margin based on name plate or de-rated capacity (e.g. for renewables) − Different treatment of intertie benefits, load growth uncertainty, etc. ▀ More explicit recognition of these wide difference would provide much-needed flexibility in market design for resource adequacy and flexibility needs 13 brattle.com III. ERCOT vs. FERC Study Design ▀ ▀ The study design for FERC was based on a hypothetical but realistic, medium-sized “Study RTO” Unlike ERCOT, the Study RTO has significant transmission interconnections to three similarly-sized neighboring regions − Realistic resource mix based on scaled NYISO, MISO, PJM, and Southern Company data − Weather (hourly load and renewable generation) based on actual TVA, MISO, PJM, and SoCo data Neighbor 1 60,000 MW SPP 56,000 MW 810 MW 3,000 MW 5,180 MW 4,000 MW 4,000 MW ERCOT 71,000 MW 280 MW Mexico 10,000 MW (Coahuila, Nuevo Leon, & Tamaulipas) Entergy 27,000 MW Neighbor 2 40,000 MW Study RTO 50,000 MW 3,000 MW Neighbor 3 30,000 MW 14 brattle.com III. Sensitivity to Intertie Capacity ▀ ▀ ▀ Overall, the results in FERC Study are very similar to ERCOT Report; however, difference in study scope provides additional insights on a number of topics Size of interconnection to neighboring system has large impact on both 1-in10 (blue dots) and economically-optimal reserve margins (red dots) Strongly dependent reserve margins in neighboring systems Total System Costs vs. Reserve Margin with Varying Intertie Assumptions 15 brattle.com III. Capacity Value of Demand Response ▀ Simulations of different levels of economic and (call-hour-limited) emergency DR show significant benefits of DR with economically optimal levels in 8%-14% range − Lower total costs, improved scarcity pricing, lower capacity prices ▀ Capacity value decreases with higher penetration for: (a) emergency DR with callhour limits and (b) economic DR with bid caps Approximate Emergency DR Dispatch Hours at Varying DR Penetration Levels Emergency DR’s Effective Load Carrying Capability (Varying DR Penetration and Call Hours) 16 brattle.com III. Impact of Price Caps ▀ ▀ ▀ Simulations show that price caps substantially reduce the equilibrium reserve margins that can be achieved by energyonly market Energy Margins and Capacity Prices (“Missing Money”) at Different Price Caps Energy market prices capped at levels below $3,000/MWh significantly increase the “missing money” at any particular reserve margin Price caps shift necessary generator revenues from energy market to capacity market; reducing dispatch efficiencies and demand response during scarcity pricing periods 17 brattle.com III. Economic RM vs. Cost of New Entry ▀ ▀ Economicallyoptimal reserve margins decrease as the marginal cost of adding new resources increases Allows estimation of a capacity market “demand curve” that is not dependent on estimates for Net CONE Cost-Minimizing Reserve Margin with Varying CT CONE (Risk-Neutral, Cost of Service Perspective) 18 brattle.com III. Demand-Curves for Capacity Markets ▀ ▀ Economicallydetermined demand curves for capacity are in the general range of RTOs’ actual demand curve Very sensitive to market structure (such as interties with neighboring systems) and market design features (such as price caps) Cost-Minimizing Capacity Demand Curve from FERC Study vs. Current RTO Demand Curves 19 brattle.com IV. Characteristics of Successful Capacity Markets Experience from the last decade strongly suggests that successful capacity markets require: 1. 2. Well-defined resource adequacy objectives and drivers Clear understanding why market design is deficient without capacity market (inefficient or not able to achieve resource adequacy targets) 3. Clearly-defined capacity products, consistent with needs 4. Well-defined obligations, auctions, verifications, and monitoring 5. Efficient spot markets for energy and ancillary services 6. Addressing locational reliability challenges 7. Participation from all resource types 8. Carefully-designed forward obligations 9. Staying power to reduce regulatory risk while improving designs and addressing deficiencies 10. Capitalizing and building on experience from other markets 20 brattle.com IV. Some Caution About Capacity Markets Market-based mechanisms, including capacity markets, offer unique efficiency and innovation advantages, reducing out-of market costs imposed on consumers But don’t prematurely add capacity markets… …that explicitly or inadvertently: ▀ − − − ▀ ▀ ▀ discriminate between existing and new resources exclude participation by demand-side and renewable resources ignore locational constraints and transmission interties …just to add revenues for certain resources or to address a perceived lack of long-term contracting …while also providing out-of-market payments (including long-term contracts) to some resources that oversupply the market and distort both short- and long-term investment signals …without understanding and addressing deficiencies in energy and ancillary service markets 21 brattle.com V. Policy Implications ▀ The most appropriate market design (and reserve margin) depends on a regions’ policy objectives and risk tolerance: − Energy-Only Market: likely the most appropriate design if economic efficiency is the primary policy objective, and the anticipated reserve margin, outage levels, and potential for periodic scarcity events is sustainable from a public policy perspective − Mandated Reserve Margins (e.g., implemented with Capacity Market): likely the most appropriate design if maintaining physical resource adequacy standards is the primary policy concern or policy makers wish to prevent potential low-reliability, high-cost events (thereby creating potential long-run benefits through risk-mitigation) ▀ Addressing this market design question appears to be less pressing while reserve margins are high, but doing so before reserve margins fall will: − Enable market participants to plan investment and contracting decisions under less regulatory uncertainty, and − If opting for a reserve margin mandate, provide sufficient time to carefully develop and implement the market design to avoid design flaws introduced through hasty implementation 22 brattle.com Appendix A: Additional FERC Study Results Uncertainties Considered in FERC Study ▀ Key uncertainties considered in FERC Study: − Forced/planned generation outages and intertie-transmission derates − Weather-related impacts on load and renewable generation (32 weather years) − Economic load-growth uncertainty over range of forward periods (1 to 10 years, 4-yr base) ▀ Administrative scarcity pricing, reserve depletion, DR- and emergency-generation Study RTO Summer Peak Load under Different Weather Profiles Economic Load Forecast Error vs. Forward Planning Period 24 brattle.com FERC Study Results Planning Reserve Margins Required to Meet Different Physical Reliability Standards 25 brattle.com FERC Study Results Distribution of Loss of Load Hours at 12% Planning Reserve Margin Across Months (Left) and Across Simulation Years (Right) 26 brattle.com FERC Study Results: Spot Energy Prices Price Duration Curve at the Equilibrium Reserve Margin 27 brattle.com Sensitivities: Physical and Economic RM Reliability-Based and Economically-Based Reserve Margin Targets (Across Base and Sensitivity Case Simulations) Simulation 0.1 LOLE Reliability-Based 2.4 LOLH 0.001% Normalized EUE Risk-Neutral, Cost-Minimizing Cost-of-Service Societal Perspective Perspective Base Case 15.2% 8.2% 9.6% 10.3% 7.9% Lower Price Caps $1,000 Price Cap Case $3,000 Price Cap Case 15.2% 15.2% 8.2% 8.2% 9.6% 9.6% 8.7% 9.5% 7.9% 7.9% Smaller System Size 40% Size Case 40% Size and Transmission 14.8% 15.1% <6% 6.9% 7.5% 8.1% <6% <6% <6% <6% Neighbor Assistance Long Neighbors Case 50% Transmission Case Island Case 13.0% 15.8% 18.5% <6% 9.8% 16.5% 7.0% 10.0% 15.8% 8.0% 12.3% 16.5% <6% 10.5% 16.5% Marginal CC Case 15.3% 8.3% 9.8% 10.1% 7.7% 28 brattle.com Additional Sensitivities: Economic RM Sensitivity of Economically Optimal Reserve Margin to Economic Study Assumptions (Risk Neutral, Cost-of-Service Perspective) Reserve Margin Range (% ICAP) Base Case Low/High Sensitivity 10.30% n/a n/a Emergency Event Costs Emergency Generation Emergency DR Emergency Hydro Voltage Reduction VOLL All Emergency Event Costs 10.2% - 10.5% 9.9% - 10.9% 10.2% - 10.5% 10.2% - 10.4% 10.0% - 11.6% 9.2% - 12.1% $500/MWh $2000/MWh $3,000/MWh $7,000/MWh $7,500/MWh Base $250 - $1000/MWh $1000 - $3000/MWh $1,500 - $6,000/MWh $3,500 - $14,000/MWh $3,750 - $15,000/MWh 50% or 200% Base Other Assumptions Load Forecast Error CONE Transmission Ownership 9.4% - 11.0% 9.5% - 11.3% 8.3% - 12.3% 4 Years Forward $120/kW-y 50/50 Ownership 2 Years - 6 Years $100 - $140/kW-y Importer/Exporter Owns Base Case 29 brattle.com -pendi I Iu::.c kl San? (II I Characteristics of Successful Capacity Markets 1. Well-defined resource adequacy objectives and drivers ▀ Meet seasonal/annual peak loads or ramping/flexibility constraints? ▀ Drivers of the identified needs? ▀ System-wide or location-specific due to transmission constraints? ▀ ▀ Near-term vs. multi-year forward deficiencies? Uncertainty of projected multi-year forward needs? Ability of all demand- and supply-side resources , including interties, to meet the identified need? 31 brattle.com Characteristics of Successful Capacity Markets 2. Clear understanding why the market design is inefficient or will not achieve resource adequacy targets without a capacity market ▀ ▀ ▀ ▀ ▀ Energy market designs that lead to price suppression? − − − − Low price caps and inadequate scarcity pricing? Poor integration of demand-response resources? Substantial locational differences not reflected in market prices? Operational actions that depress clearing prices? Challenging investment risks (e.g., in hydro-dominated markets)? Distortions created by out-of-market payments for some resources that lead to over-supply or high costs? Incomplete or poorly-designed ancillary service markets? − Missing ramping products? − Not co-optimized with energy market? − Operational actions that depress clearing prices? Most Likely: Resource adequacy preferences higher than what even fully-efficient energy and ancillary service markets would provide 32 brattle.com Characteristics of Successful Capacity Markets 3. Clearly-defined capacity products, consistent with needs ▀ Annual and seasonal capability ▀ Near-term or multi-year forward obligations ▀ Peak load carrying vs. ramping capability ▀ ▀ Effective load carrying capability and outage rates of different resource types (including renewables, demand-response, and interties) Integration with energy and ancillary service markets 4. Well-defined obligations, auctions, verifications, monitoring, and penalties ▀ Ensure quality of resources and compliance without creating inadvertent bias against certain resources (e.g., demand-response, intermittent resources, imports) 33 brattle.com Characteristics of Successful Capacity Markets 5. Efficient spot markets for energy and ancillary services ▀ ▀ Capacity markets can “patch-up” deficiencies in energy and ancillary service markets from a resource adequacy perspective Less efficient investment signals (e.g., resource types, supply- vs. demand-side resources, locations) if deficiencies in energy and ancillary service are not addressed 6. Addressing locational reliability challenges ▀ ▀ ▀ Resource adequacy won’t be addressed efficiently if reliability concerns are locational but capacity markets aren’t Requires locational resource adequacy targets and market design Requires understanding of how transmission (including interties between power markets) affect resource adequacy 34 brattle.com Characteristics of Successful Capacity Markets 7. Participation from all resource types ▀ ▀ ▀ ▀ Existing and new generating plants Conventional, renewable/intermittent, and distributed generation Load (demand response) Interties (actively committed imports vs. resource adequacy value of uncommitted interties) 8. Carefully-designed forward obligations ▀ ▀ ▀ ▀ Efficiency of near-term obligations (avoid forecasting uncertainty, adjust to changes in market conditions, reduced commitment risk) Benefits of multi-year forward obligations (competition between new and existing resources; forward visibility; financial certainty) Questionable need for forward commitments greater than 3-4 years Avoid capacity markets as substitute for long-term contracts 35 brattle.com Characteristics of Successful Capacity Markets 9. Staying power to reduce regulatory risk while improving designs ▀ ▀ ▀ Staying power of market design reduces regulatory risk and improves investment climate Requires careful balancing of staying power and the need to improve design elements and address deficiencies Challenge due to strong financial interests of different stakeholders 10. Capitalizing and building on experience from other markets ▀ Regional difference are important but often overstated ▀ Avoid the “not invented here” syndrome ▀ Avoid “urban myths” (e.g., no new generation built in regions with capacity markets; insufficient to support merchant investments unless 5-10 year payments can be locked in) 36 brattle.com Appendix C: Additional Reading, About the Authors and Brottle Additional Reading Newell, Spees, Pfeifenberger, Karkatsouli, Wintermantel, Carden. Estimating the Economically Optimal Reserve Margin in ERCOT, Report prepared for the PUCT, January 31, 2014. Pfeifenberger. Market-based Approaches to Resource Adequacy, IESO Stakeholder Summit, Feb. 11, 2014. Pfeifenberger, Spees. Characteristics of Successful Capacity Markets, APEx Conference, October 31, 2013. Pfeifenberger, Spees, Carden and Wintermantel, Resource Adequacy Requirements: Reliability and Economic Implications, Report prepared for FERC, September 2013. Spees, Newell, Pfeifenberger. “Capacity Markets: Lessons Learned from the First Decade,” Economics of Energy & Environmental Policy. Vol. 2, No. 2, September 2013. Spees, Pfeifenberger. “PJM’s Energy and Capacity Markets: Outlook on Fundamentals,” 12th Annual Power &Utility Conference, Goldman Sachs, August 8, 2013. Pfeifenberger, Spees. “Evaluation of Market Fundamentals and Challenges to Long-Term System Adequacy in Alberta’s Electricity Market,” March 2013 (Update) and April 2011 (Original Study). Pfeifenberger. “Structural Challenges with California’s Current Forward Procurement Construct.” CPUC and CAISO Long-Term Resource Adequacy Summit. San Francisco, February 26, 2013 Newell, Spees. “Get Ready for Much Spikier Energy Prices: The Under-Appreciated Market Impacts of Displacing Generation with Demand Response.” February 2013. Pfeifenberger, Spees, Newell. “Resource Adequacy in California: Options for Improving Efficiency and Effectiveness,” October 2012. Newell, Spees, Pfeifenberger, Mudge, DeLucia, Carlton, “ERCOT Investment Incentives and Resource Adequacy,” June 2012. 38 brattle.com Additional Reading (cont’d) Pfeifenberger, Newell. “Trusting Capacity Markets: Does the Lack of Long-Term Pricing Undermine the Financing of New Power Plants?” Public Utilities Fortnightly. December 2011. Pfeifenberger, Newell, Spees, Hajos, Madjarov. “Second Performance Assessment of PJM’s Reliability Pricing Model: Market Results 2007/08 through 2014/15.” August 26, 2011. Spees, Newell, Carlton, Zhou, Pfeifenberger. “Cost of New Entry Estimates for Combustion Turbine and Combined-Cycle Plants in PJM.” August 24, 2011. Carden, Pfeifenberger and Wintermantel. “The Economics of Resource Adequacy Planning: Why Reserve Margins Are Not Just About Keeping the Lights On.” NRRI Report 11-09. April 2011. Newell, Spees, Hajos. “The Midwest ISO’s Resource Adequacy Construct: An Evaluation of Market Design Elements.” The Brattle Group, January 19, 2010. Newell, Bhattacharyya, Madjarov. “Cost-Benefit Analysis of Replacing the NYISO’s Existing ICAP Market with a Forward Capacity Market." June 15, 2009. LaPlante, Chao, Newell, Celebi, Hajos. “Internal Market Monitoring Unit Review of the Forward Capacity Market Auction Results and Design Elements.” ISO New England and The Brattle Group. June 5, 2009. Pfeifenberger, Spees. “Best Practices in Resource Adequacy.” PJM Long Term Capacity Issues Symposium. January 27, 2010. Pfeifenberger, Spees, Schumacher. “A Comparison of PJM's RPM with Alternative Energy and Capacity Market Designs.” September 2009. Pfeifenberger, Newell, Earle, Hajos, Geronimo. “Review of PJM's Reliability Pricing Model (RPM).” June 30, 2008. Reitzes, Pfeifenberger, Fox-Penner, Basheda, Garcia, Newell, Schumacher. “Review of PJM’s Market Power Mitigation Practices in Comparison to Other Organized Electricity Markets,” September 2007. 39 brattle.com Author Contact Information JOHANNES P. PFEIFENBERGER Principal │ Cambridge, MA Hannes.Pfeifenberger@brattle.com +1.617.234.5624 SAMUEL A. NEWELL Principal │ Cambridge, MA Samuel.Newell@brattle.com +1.617.234.5725 KATHLEEN SPEES Senior Associate │ Cambridge, MA Kathleen.Spees@brattle.com +1.617.234.5783 40 brattle.com About the Brattle Group The Brattle Group provides consulting and expert testimony in economics, finance, and regulation to corporations, law firms, and governmental agencies worldwide. We combine in-depth industry experience and rigorous analyses to help clients answer complex economic and financial questions in litigation and regulation, develop strategies for changing markets, and make critical business decisions. Our services to the electric power industry include: ▀ ▀ ▀ ▀ ▀ ▀ ▀ ▀ ▀ ▀ Climate Change Policy and Planning Cost of Capital Demand Forecasting Methodology Demand Response and Energy Efficiency Electricity Market Modeling Energy Asset Valuation Energy Contract Litigation Environmental Compliance Fuel and Power Procurement Incentive Regulation ▀ ▀ ▀ ▀ ▀ ▀ ▀ ▀ ▀ ▀ Rate Design and Cost Allocation Regulatory Strategy and Litigation Support Renewables Resource Planning Retail Access and Restructuring Risk Management Market-Based Rates Market Design and Competitive Analysis Mergers and Acquisitions Transmission 41 brattle.com Offices NORTH AMERICA Cambridge New York San Francisco Madrid Rome Washington, DC EUROPE London 42 brattle.com From: To: Subject: Date: Teresa Tenbrink "Bostian, Trudi" RE: Invitation to the Harvard Electricity Policy Group 74th Plenary Session, Feb 27-28, 2014 Wednesday, February 19, 2014 11:21:00 AM Great!  Thank you Trudi!   Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   From: Bostian, Trudi [mailto:Trudi_Bostian@hks.harvard.edu] Sent: Wednesday, February 19, 2014 8:05 AM To: Teresa Tenbrink Subject: RE: Invitation to the Harvard Electricity Policy Group 74th Plenary Session, Feb 27-28, 2014   Hello,   Her confirmation number is 15090711.   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: Teresa Tenbrink [mailto:ttenbrink@azcc.gov] Sent: Tuesday, February 18, 2014 1:17 PM To: Bostian, Trudi Subject: RE: Invitation to the Harvard Electricity Policy Group 74th Plenary Session, Feb 27-28, 2014   Hi Trudi,    Can you confirm that you have hotel reservations for Commissioner Susan Bitter Smith?  I am sure that you have them.  I am double checking myself.   Thanks, Teresa     Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625     From: Bostian, Trudi [mailto:Trudi_Bostian@hks.harvard.edu] Sent: Wednesday, January 22, 2014 08:26 AM To: Susan Bitter Smith Subject: Invitation to the Harvard Electricity Policy Group 74th Plenary Session, Feb 27-28, 2014   Dear Commissioner Bitter Smith,   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   ========================================== 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: Cc: Subject: Date: Attachments: Teresa Tenbrink Peter Vazquez Kim Battista; Jodi Jerich Travel request for Commissioner Susan Bitter Smith Feb 26-28, 2014 Tuesday, February 18, 2014 11:51:00 AM Out_of_State_Travel_Request.xls HEPG Santa Monica Meeting Logistics.msg Commissioner Bitter Smith will be traveling to Santa Monica to attend the Harvard Energy Policy Group’s meeting.  Attached is her invitation.    Thanks, Teresa ARIZONA CORPORATION COMMISSION OUT-OF-STATE TRAVEL APPROVAL REQUEST In accordance with A.R.S. § 38-626A, approval is requested for the following out-of-state travel: NAME: TITLE: TO: Susan Bitter Smith Commissioner Kim Battista, Administrative Services Director Jodi Jerich, Executive Director 2/18/2014 DATE: DIVISION: Commissioner Bitter Smith's office ****************************************************************************************************************************************************************** Wednesday, Feb. 26th at DATE/TIME DEPARTING PHOENIX: 7:45pm FINAL DESTINATION: Santa Monica, CA DATE/TIME RETURNING: Friday, Feb 28th at 6:45pm ****************************************************************************************************************************************************************** PURPOSE OF TRIP: Commissioner Bitter Smith is flying to L.A. to attend the Harvard Energy Policy Group's Seventy-Fourth Flenary Session held in Santa Monica, CA. All her travel expenses will be reimbursed by the host (HEPG). See the attached invitation. APPROVED:_____________________________ Division Director DATE REVIEWED:_____________________________ Business Office DATE APPROVED:_____________________________ Supervisor DATE APPROVED:_____________________________ Executive Director or DATE Administrative Services Director ****************************************************************************************************************************************************************** ESTIMATED TRAVEL EXPENSES: AIRFARE 6611 $230.00 RENTAL CAR 6621 - LODGING 6631 - MEALS & INCIDENTALS 6641 SUBTOTAL: $230.00 TAXI/PARKING PERSONAL MILEAGE OTHER MISCELLANEOUS SUBTOTAL OTHER 6699 $0.00 REGISTRATION FEE 7455 - ESTIMATED TOTAL COSTS Is Airfare REFUNDABLE? Y N Please attach justification memo to use a rental car. Is Lodging @ CONFERENCE RATE If not, is Lodging within Travel Policy allowance for the city/county? Y N Y N* * If Lodging is not within the Travel Policy allowance, please submit a justification memo to the Administrative Services Director, who will then request a waiver from the GAO. Has the Registration Fee been paid? f Yes, was the VISA travel-card used? Y Y N N $230.00 REMINDER: ANY INDIVIDUAL COST GREATER THAN $1000 MUST BE ENCUMBERED. WHEN EXCEPTIONS TO THE STATE TRAVEL POLICY ARE ANTICIPATED, FORWARD A POLICY EXCEPTION REQUEST TO THE ADMINISTRATIVE SERVICES DIRECTOR, OR THE CHIEF FINANCIAL OFFICER. The Arizona State Travel Policy requires that a formal request for approval be submitted when certain travel conditions are anticipated (e.g., lodging charges in excess of allowable limits.) Substitute GAO - 509 (GAO approval ) 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: Mahoney, Jo-Ann [] To: Mahoney, Jo-Ann [Jo-Ann_Mahoney@hks.harvard.edu] CC: Bostian, Trudi [Trudi_Bostian@hks.harvard.edu] Subject: HEPG Santa Monica Meeting Logistics Sent: Thursday, February 06, 2014 09:38:17 Attachment 1: 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 file:///ACCData/...PG%20Santa%20Monica%20Meeting%20Logistics.msg.folder/HEPG%20Santa%20Monica%20Meeting%20Logistics.txt[2/14/2017 8:54:06 AM] From: To: Cc: Subject: Date: Attachments: Teresa Tenbrink jo-ann_mahoney@harvard.edu Trudi_bostian@hks.harvard.edu HEPG Seventy-Fourth Plenary Session in Santa Monica, CA Wednesday, January 22, 2014 3:26:00 PM HEPG Santa Monica, CA.pdf Hi Jo-Ann & Trudi,   I have attached the registration form for Commissioner Susan Bitter Smith.  She will be attending both days (Feb 27 & Feb 28).  She will need hotel reservations for Wednesday, February 26th and Thursday, February 27th.    Thanks, Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625   TO: ROM: REGISTRATION FORM HEPG SEVENTY-FOURTH PLENARY SESSION THURSDAY AND FRIDAY, FEBRUARY 27-28, 2014 SHUTTERS ON THE BEACH SANTA MONICA, CALIFORNIA HARVARD ELECTRICITY POLICY GROUP John F. Kennedy School of Government Name Swan B?r?wSmulk Tide Af?liation WESTON Address ?-00 LU - mack?mqlm Ptoen?nx?z. Phone 1601) San?seas" E?mail or YES, I will be able to attend the HEPG Plenary Session. Address NO, I will not be able to attend the meeting. I would like tO send my designee: 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: Mahoney, HEPG Program Director Fax: (617) 495?1635 Phone: (617) 495-1390 email to: From: To: Subject: Date: Susan Bitter Smith "Trudi_Bostian@hks.harvard.edu" Re: Invitation to the Harvard Electricity Policy Group 74th Plenary Session, Feb 27-28, 2014 Wednesday, January 22, 2014 11:08:37 AM Trudi, I would love to come- I learned so much last time. I will return the form to you but would need hotel both nights. Thank you. Susan From: Bostian, Trudi [mailto:Trudi_Bostian@hks.harvard.edu] Sent: Wednesday, January 22, 2014 08:26 AM To: Susan Bitter Smith Subject: Invitation to the Harvard Electricity Policy Group 74th Plenary Session, Feb 27-28, 2014 Dear Commissioner Bitter Smith,   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   From: To: Subject: Date: Attachments: Susan Bitter Smith Teresa Tenbrink Fw: Invitation to the Harvard Electricity Policy Group 74th Plenary Session, Feb 27-28, 2014 Wednesday, January 22, 2014 9:45:13 AM Registration_form_2-14_comm.docx I plann to go- can we get the form filled out? I will need both nights of hotel. From: Bostian, Trudi [mailto:Trudi_Bostian@hks.harvard.edu] Sent: Wednesday, January 22, 2014 08:26 AM To: Susan Bitter Smith Subject: Invitation to the Harvard Electricity Policy Group 74th Plenary Session, Feb 27-28, 2014 Dear Commissioner Bitter Smith,   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 From: To: Subject: Date: Attachments: Bostian, Trudi Susan Bitter Smith Invitation to the Harvard Electricity Policy Group 74th Plenary Session, Feb 27-28, 2014 Wednesday, January 22, 2014 8:28:52 AM Registration_form_2-14_comm.docx Dear Commissioner Bitter Smith,   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 From: To: Subject: Date: Bostian, Trudi Teresa Tenbrink RE: HEPG Expense Form for Commissioner Susan Bitter Smith Friday, January 10, 2014 10:34:13 AM That's fine, 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 -----Original Message----From: Teresa Tenbrink [mailto:ttenbrink@azcc.gov] Sent: Friday, January 10, 2014 12:02 PM To: Bostian, Trudi Subject: RE: HEPG Expense Form for Commissioner Susan Bitter Smith I used .45.  It's the state government rate. Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625 -----Original Message----From: Bostian, Trudi [mailto:Trudi_Bostian@hks.harvard.edu] Sent: Friday, January 10, 2014 9:57 AM To: Teresa Tenbrink Subject: RE: HEPG Expense Form for Commissioner Susan Bitter Smith Hi Teresa, What mileage rate did you use?  The university is rate is .565 (2013 rate) (2014 is .56). 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 -----Original Message----From: Teresa Tenbrink [mailto:ttenbrink@azcc.gov] Sent: Thursday, January 02, 2014 11:21 AM To: Bostian, Trudi Subject: HEPG Expense Form for Commissioner Susan Bitter Smith Dear Trudi, Please find attached Commissioner Bitter Smith's Expense form for the HEPG's Seventy-Third Plenary Session in Marana, Arizona.  Please let me know if you need anything further.  Thanks! Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625 =========================================== This footnote confirms that this email message has been scanned to detect malicious content. If you experience problems, please contact postmaster@azcc.gov              =========================================== =========================================== This footnote confirms that this email message has been scanned to detect malicious content. If you experience problems, please contact postmaster@azcc.gov              =========================================== From: To: Subject: Date: Attachments: Teresa Tenbrink "trudi_bostian@hks.harvard.edu" HEPG Expense Form for Commissioner Susan Bitter Smith Thursday, January 02, 2014 9:21:00 AM Scanned from a Xerox multifunction device.pdf Dear Trudi, Please find attached Commissioner Bitter Smith's Expense form for the HEPG's Seventy-Third Plenary Session in Marana, Arizona.  Please let me know if you need anything further.  Thanks! Teresa Tenbrink Executive Aide to Commissioner Susan Bitter Smith Arizona Corporation Commission 1200 W. Washington Phoenix, AZ 85007 (602) 542-3625 HARVARD UNIVERSITY UNIVERSAL EXPENSE FORM EMPLOYEE TYPE OR AFFILIATION PAYMENT TYPE ONLYONE) Harvard Employee ?out of Pocket Af?liate/Harvard Student/CasuallStipend - complete shaded areas [3 American Express Corporate Card Invited Guesthisitor - complete shaded areas Date: Reimbursee or Cardholder Name: Web Voucher/PO#: l1~l?43 Sosan Social Sec/Tax lD#; Harvard US Citizen or Permanent Resident: __V_7_Yes No Redacted Permanent Residents indicate Resident alien card Personal Information 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 andlor organization visited and location. Also include expense date range. List additional business purposes on page 2.) #1 Psi?is Travel (mm ?Scot?rsdale to Harm E2 #2 l2?I3A5'vaol Mm MUM, R2 to (Otis #3 Datets} of eXpensets) #4 #5 SUMMARY OF EXPENSES (Room for additional expenses is available on page 2) 23:21:: (datEESSi?t?i'ittl ?li?aiiZl tit? Lodging Other Total ell?is grows Transpar - - - (to ?8 2, 2~l3?l3 GimmATmr'LSEm?qlv' on Lita-23 ?5'23 Subtotals from page 2, if applicable: 012.51, ?12 SE) Less Advances: EXPE EREPORT TOTAL: Sig 2.51, TOTAL AMOUNT OF UNDER $75: 5 I REIMBU RSEE: I certify tthese are all legitimate Harvard University business expenses. SIGNATURE: Date: IQ ~92 3-43 Redacted- Personal Information Reimbursee'Permanent Legal Address: Reimbursee Ch ck Mailing Address if mere 1?00er on Wigsioan i335: lW IZOD Prioerfix, HZ. m0? Preparer: . Phone: A pprover: . (PRINT) (SIGNA TURE) I have reviewed these expenses and all are In accordance with Um'versigi and Tub policy.