September 12-14, 2012 The Broadmoor, Colorado Springs, CO Edison Electric Institute Power by Associations" 2012 Fall Board and Chief Executives Meeting S CHEDULE OF E VENTS September 12-14, 2012 The Broadmoor Colorado Springs, CO WEDNESDAY, SEPTEMBER 12, 2012 8:00 a.m. – 6:00 p.m. EEI Office and Registration McGrew Room 12:00 N – 2:00 p.m. Western CEO Meeting West Ballroom A/B 12:30 p.m. – 2:00 p.m. PJM CEO Meeting West Ballroom C/D 2:00 p.m. – 3:30 p.m. MISO CEO Meeting Rocky Mountain C 3:30 p.m. – 5:00 p.m. Executive Committee Meeting West Ballroom A/B 6:00 p.m. – 9:00 p.m. Welcome Reception and Dinner Cheyenne Lodge THURSDAY, SEPTEMBER 13, 2012 7:00 a.m. – 5:00 p.m. EEI Registration Rocky Mountain A/B Foyer 7:00 a.m. – 8:00 a.m. IEE Management Committee West Ballroom A/B 7:30 a.m. -- 8:00 a.m. Conference Breakfast Rocky Mountain C/D 8:00 a.m. – 9:30 am. 2012 Election Outlook Haley Barbour, Former Mississippi Governor Robert Gibbs, Former White House Press Secretary Guest Program Rocky Mountain C/D 9:30 a.m. – 12:15 p.m. Board of Directors Strategic Discussion Dodd-Frank/Dividends Natural Gas Roundtable Infrastructure Investment Challenge Distribution 2020 Bulk Power System Rocky Mountain A/B 12:15 p.m. – 2:00 p.m. Conference Luncheon The Fiscal Road Ahead: Former U.S. Sen. Alan Simpson Rocky Mountain C/D 10:00 a.m. – 12:00 p.m. Wi-Fi Connection for EEI Meeting Areas – Username: EEI Crystal Room  Password: 123 Schedule of Events EEI 2012 Fall Board and Chief Executives Meeting – September 12-14, 2012 2:00 p.m. – 4:30 p.m. Board of Directors Strategic Discussion Storm Resiliency/Response Cybersecurity NERC Issues FERC Issues Environment Issues Electric Transportation Campaign EEI Smart Grid Rapid Response 4:30 p.m. – 5:00 p.m. Board of Directors Meeting – Business Session 5:30 p.m. – 7:00 p.m. Conference Reception Rocky Mountain A/B Lake Terrace Dining Room FRIDAY, SEPTEMBER 14, 2012 6:00 a.m. – 1:00 p.m. EEI Office McGrew Room 6:00 a.m. – 9:00 a.m. Buffet Breakfast available Rocky Mountain C/D 7:00 a.m. – 11:00 a.m. Classified CEO Cybersecurity Briefing (By Invitation Only) Offsite Location 11:00 a.m. Buffet Luncheon Available Mountain View Terrace Wi-Fi Connection for EEI Meeting Areas – Username: EEI  Password: 123 2012 Fall Board and Chief Executives Meeting PJM CEO M EETING Wednesday, September 12, 2012  12:30 p.m. – 2:00 p.m. Executive Session: Regular Meeting: The Broadmoor West Ballroom C/D 12:30 – 12:45 PM 12:45 – 2:00 PM I. Welcome and Introductions William H. Spence, Chairman, President & CEO, PPL Corp II. PJM Update Terry Boston, President & CEO, PJM A. EPA Regulations Compliance  Generator Retirement/Outage Coordination   Gas/Electric Coordination Reliability on the MISO Seam B. MISO Seams Issues and Coordination   Resource Adequacy (Capacity Portability) Market Operations  Transmission Planning  Broader Regional Markets C. Order No. 1000 Compliance   Cost Allocation Reform - Transmission Owners Agreement on Cost Allocation Transmission Planning Reform  Nonincumbent Developer Reforms  Interregional Coordination Efforts D. Reliability Pricing Model   March 2012 Action Item - Media/PR Piece(s) on Benefits of RPM 2015-2016 Auction - Market Results - Demand Response Penetration  Minimum Offer Pricing Rule  State Actions Update E. Other Issues  III. Operation and Performance of Demand Response Action Items/Next Steps 2012 Fall Board and Chief Executives Meeting MISO CEO M EETING Wednesday, September 12, 2012  2:00 p.m. – 3:30 p.m. Executive Session: Regular Meeting: The Broadmoor Rocky Mountain C 2:00 – 2:15 PM 2:15 – 3:30 PM I. Welcome and Introductions Charles A. Schrock, Chairman, President and CEO, Integrys Energy Group, Inc. II. MISO Update John R. Bear, President and CEO, MISO A. Entergy and Cleco Integration  State Functions and Filing Rights  Regulation and Integration Timeline B. EPA Regulations Impact & Outage Coordination  Action Item From June: EEI Members Response to MISO Survey and Results  Generator Retirement/Outage Coordination Effort - Regional Reliability Concerns - Revisions to Generator Retirement Process (Att. Y and SSRs)  Gas/Electric Coordination C. Order No. 1000 Compliance  System Planning and Cost Allocation  Right of First Refusal  Interregional Coordination Efforts D. PJM Coordination  FERC Request for Comment & Related Proceedings  Joint MISO and PJM Stakeholder Efforts E. Other Issues  III. Seams Coordination Action Items/Next Steps EEI Board & CEO Meetings ■ Sept. 13, 2012 ■ The Broadmoor ■ West Ballroom A&B ■ CO Springs IEE Management Committee Meeting SAVE the DATE Thursday, September 13, 2012 West Ballroom A & B Breakfast starting – 6:45 am Meeting – 7:00 – 8:00 am This meeting will focus on IEE’s strategic focus over the next five years and what this means for the electric power industry. IEE Management Committee Co-Chairs, Peter Delaney, Chairman, President, and CEO, OGE Energy Corp., and Robert Rowe, President and CEO, NorthWestern Energy, will lead the discussion. Agenda to follow. HALEY BARBOUR BIOGRAPHY EEI Fall Board and Chief Executives Meeting, September 2012 Haley Barbour, the former governor of Mississippi and former chairman of the Republican Governor’s Association, is one of the top political strategists in the country. Barbour put Mississippi on a new path in job creation, education, health care, and energy. Barbour speaks on politics, elections, Republican strategy, the economy, job creation, and leadership. Previously Barbour successfully served twice as chairman of the Republican National Committee. In 1994, under Barbour’s chairmanship, Republicans won the greatest midterm majority sweep of the 20th century, winning GOP control of both houses of Congress for the first time in 40 years. After his stint as head of the RGA, POLITICO called Barbour “the most powerful Republican in politics.” He also recently returned to Barbour, Griffith, & Rogers (BGR Group), a lobbying group he helped found in 1991. Source: Leading Authorities ROBERT GIBBS BIOGRAPHY EEI Fall Board and Chief Executives Meeting, September 2012 Senior Advisor, President Obama's 2012 Reelection Campaign, Present White House Press Secretary, 2009-2011 A top advisor to President Obama for nearly a decade, Robert Gibbs offers a unique perspective on issues surrounding Election 2012. Gibbs also provides robust insights into policy issues impacting some of the most critical debates of the day including the economy, healthcare reform, and energy issues. As Press Secretary to President Obama, Gibbs served as the primary voice of the administration on every major issue that came across the President's desk, and in a New York Times article President Obama praised Gibbs' service: “Robert, on the podium, has been extraordinary. Off the podium, he has been one of my closest advisors. He is going to continue to have my ear for as long as I’m in this job.” Source: The Harry Walker Agency DIVIDEND TAX ISSUE EEI Fall Board and Chief Executives Meeting, September 2012 Major Progress on Dividends But a Major Push Will be Needed Since the last Board meeting significant progress has been made in setting the stage for an extension of low tax rates on dividends, however nothing short of an all out push will be needed through the summer and into the Lame Duck to win this issue. Nearly 60 EEI member companies and other allies are partners in the Defend My Dividend campaign, which has generated nearly 125,000 e-mails and phone calls to Members of Congress to date. In addition, the House voted on a one-year extension of the current rates, and the Senate has voted on a measure that would cap the upper rate for dividends and cap gains at 20%, recognizing the tax rate parity argument advocated by EEI. During the past quarter, our activities have included:  Organizing a major Congressional briefing on the dividends issue at the Congressional Visitors Center in the Capitol to launch the Ernst & Young dividends study  Major advocacy before the Congress  A CEO Congressional fly-in  A CFO Congressional fly-in  Significant earned media both print, television and social media  Grassroots activation and coalition building Although good progress had been made, the final action on the dividend tax issue will occur this fall. It is imperative that the industry maintain and increase our efforts. EEI Board Leads: Thomas A. Fanning, Chairman, President & CEO, Southern Company Benjamin Fowke, III, Chairman, President & CEO, Xcel Energy, Inc. EFENI IIVIIENI Campaign Update Brian L. Wolff EEI Board of Directors Meeting September 13, 2012 Edison Electric Institute Pan/er by Assum'an'on The Challenge Obama’s budget plan hammers investors House heading toward election-year tax showdown July 19, 2012 Ending Bush Tax Cuts for Rich Would Save About $80 Billion in 2013, Analysts Say 3 Implementing Our Plan Phase 3: Pre- and Post-Election Day Push  Earned media outreach  Begin paid media campaign  Leadership CEO & CFO fly-ins on Capitol Hill  Congressional briefing on Ernst & Young study  Member companies meet with congressional delegations  “Dividends In The District” 5 Changing the Conversation: Engaging the Media ?hch FIGHT THE FISCAL CLIFF PUSH: Campaigning To Extend Current 15% Tax Rate .. ON 0n Dividend Income if Tax Rates Increase. it Will Hurt Millions Of Individuals At EVEN Income Dividend Taxes Represent a Second Layer 0f Taxation Wovldwide. Fits! in ?usinoss Wocldwidu. a Fitst in Business W0: WASHINGTON if i PAUL FARR ERGO 2,550.25 Wand-?ve. A Fitst in Business Wocldwidc. Hist in Business War Changing the Conversation: CEOs CFOs Speak Out 'uc?sday?. Jul-5' cf PM New 5.39:: THE Will STREET JOURNAL. OPINION charlotteobserver.com VieWpoint - People In Thor-Jews. - - Ellags. - Wond U.S. New Tort: Business Markets Tech I Personal Finance Lite 3. Culture Sports: Entertainment Ll'u'irtgHere Business: Kevin Siers I EIlogsa?Columnists I OPINION Li?; 5' FORTHERECORD LEWIS The Tax Senlors Congress should extend tax reduction on dividend income i3 lftemporary measure isn't EHEHGEU. companies. WDUIU Pcsted: 'hureday. Jul. 12. 2012 From Good, Chief Financial Officer at Duke Energy: MercuryNewscom Subscribell-lanage Tribune acct. Aa'tsrtise 't't'i . Tony Earley. Stop the dwldend tax hike now in Congress 34? Partly Cloudy .com By Trent?r Special to the Mercuryr News Tom BOY Dunne Posted: AM PDT Updated= 031'191'2'3'12 PDT HOME NEWS WEATHER COMMUNITY SPORTS LIVING The Detroit News Op i ion Opinion Editorials Home News Sports Busine55+Autos Entertainment?Lifestyle Opinion BREWEM I SljecialtaTITeTamljaTrihLIne ?We Edimria's 28. 2812 AM Commentary: Time to lock in low dividend tax rate DAVID E. MEADDR 4 COMMENTS 9' Changing the Conversation: Ernst Young Report CNBC Video CLOSING ERNST 6 YOUNG REPORT100K i2.604.83 BEYOND THE 99%! Worldwide. First in Business Worldwide. Ernst 6 Young Report Shows That 68% of Filers With Dividend income In 2009. Made Less Than $100,000 First in Business Changing the Conversation: Reaching Key Audiences Consequently, the only way for the side of lower dividend tax rates to win is if enough dividend-investing Americans make their views known. … I urge you to contact www.DefendMyDividend.org or call 888443-5863. 9 Print Ad in Politico A DIVIDEND TAX HIKE FOR ALL AMERICANS a: I I- In If Congress doesn?t act soon, our current dividend tax rates will expire at the end of this year and millions of American families and seniors will see their tax rates on dividends spike?increasing 189% in some cases. Raising dividend taxes will have severe consequences. hindering economic recovery, slowing investment in US. companies. and Jeopardizing infrastructure investment projects that create American jobs. Now is the time to reduce dividend income through higher taxes and penalize Americans who invest in our nation's future. Visit to learn more. his ll": .\Ilig\iili't- l'ur . nunus I I 10 Follow us on Twitter Follow us on Twitter OLowDividendTax. Television Ads INCREASED Making Progress Legislative Proposals and Outcomes Original Proposal Outcome • GOP Plan: • GOP plan passed in House by a vote of 256-171 (August 1). • GOP plan rejected in Senate by a vote of 45-54 (July 25). Extend all 2001/2003 tax provisions for one year, including current rates on dividends • Democrat Plan: Pres. Obama proposed extending current tax rates only for taxpayers making less than $250,000 ($200,000 single). Top tax rate for capital gain increases to 20% and top rate for dividends increases to 39.6%. • House and Senate Dems modify Obama’s proposal for top tax rates, linking the tax rates on dividends and capital gains and decreasing the top rate to 20%. • House Democrat plan rejected by a vote of 170-257 (August 1). • Senate Democrat plan passed by a vote of 51-48 (July 25). Roll Call Vote on Senate Democrat Plan: 51-48 (July 25) Roll Call Vote on House GOP Plan: 256-171 (August 1) 14 July 11, 2012 Democrats Pull Away From Obama on Bush Tax Cuts August 10, 2012 Democrats’ dividend dilemma July 25, 2012 Senate Democrats Make Curious Choice To Keep Dividend Taxes Low July 15, 2012 15 The Challenge Continues July 8, 2012 Obama Poised for New Fight with G.O.P. Over Tax Cuts August 22, 2012 CBO warns of significant recession if Congress doesn’t act to avoid fiscal cliff 17 Next Steps Phase 4: Lame Duck Implementation  New ads / Continued media outreach  CEO/CFO Fly-ins continue  Lobby Days with Allies  Virtual Lobby Days 19 DODD-FRANK IMPLEMENTATION EEI Fall Board and Chief Executives Meeting, September 2012 Continued Improvements Achieved in Dodd-Frank Implementation Following passage of the Dodd-Frank financial reform bill in July 2010, EEI has been leading a multi-association campaign to preserve the over-the-counter derivatives market for utilities and other end users. EEI’s efforts have been focused on ensuring that the Commodity Futures Trading Commission (CFTC) and other regulatory agencies preserve the legislative intent of the law to avoid burdening end users. In July, the CFTC and Securities and Exchange Commission issued a long-awaited final rule to further define the terms “swap” and “security-based swap,” among other terms. The final rule is substantially improved from the May 2011 proposed rule and contains a number of significant changes advocated by EEI, including:  The rule provides additional clarification on the forward contract exclusion for nonfinancial commodities and indicates that the Commission will interpret the exclusion from the definition of “swap” and the exclusion from the definition of a futures contract consistently.  “Book-out” transactions, in which parties in a delivery chain agree to financially settle their delivery obligations for commercial efficiency, will be treated as forward contracts and not swaps.  The rule includes new interpretive guidance that is meant to clarify that certain contracts that include embedded volumetric optionality, such as full-requirements contracts, are forward contracts and not swaps.  The rule provides guidance that environmental commodities (e.g., emissions allowances and RECs) are nonfinancial commodities and qualify for the forward contract exclusion.  In another major development, the CFTC also approved the final rule governing the enduser exception to mandatory clearing. Changes from the December 2010 proposed rule indicate a clear victory for EEI’s members and other end users that use uncleared swaps to manage their commercial risks.  The rule clarifies that an end user’s board of directors can provide periodic (rather than transaction-by-transaction) approval for the end user to enter into uncleared swaps. Other key upcoming Dodd-Frank rulemakings and actions include: the capital and margin rule, the RTO products exemption request, CFTC determinations that gas transportation contracts aren’t swaps and the computation of gross notational value under the swap dealer rule. EEI is conducting member compliance forums and developing compliance products. Dodd Frank Implementation EEI Fall Board and Chief Executives Meeting, September 2012 For more information on CFTC proposed and final rules, please see http://www.eei.org/ourissues/finance/Special/CFTC-NOPRs-FinalRules8-2012.doc For more information on compliance dates, please see http://www.eei.org/ourissues/finance/Special/CWT_DFA-ComplianceDateCalendar-8-9-12.pdf EEI Board Lead: Theodore F. Craver, Jr., Chairman, President & CEO, Edison International 2 EEI Board of Directors Meeting The Broadmoor, Colorado Springs, CO September 13, 2012 DODD-FRANK SCORECARD The Commission has issued over 80 NOPRs, Interim Final Rules and other request for comment. EEI has filed over 35 sets of comments with the CFTC on various issues. As end users, EEI has identified the following rulemaking areas as having the most import for its members. While we have achieved significant positive changes in the Final Rules from the proposed rules, the devil is in the details so EEI is now shifting its focus to implementation and interpretive issues to help ensure that the rules are implemented in a manner that works for end users. Proposed Rule Positive Changes in Final Rule for EEI Members Reporting Pre-Enactment Swap Transactions X Reporting Post Enactment Swap Transactions X Prohibition of Market Manipulation [Rule unchanged from proposed rule but did receive a requested clarification] Implementing the Whistleblower Provisions [Rule unchanged from proposed rule but guidance added suggestion that whistleblowers go through internal programs first] Real Time Public Reporting of Swap Transactions and Pricing Data X Swap Data Recordkeeping and Reporting Requirements X Further Definition of Swap Dealer X End User Exception X Position Limits for Derivatives Commission issued a NOPR on aggregation provisions due to petitions for relief filed by EEI and by some of its members Commodity Options and Agricultural Swaps X Capital and Margin Requirements Final Rule not yet issued Product Definition X NATURAL GAS ISSUES EEI Fall Board and Chief Executives Meeting, September 2012 Is Natural Gas the New Coal? Unconventional gas is transforming the market for natural gas, with demand for electric generation as the key driver for new demand. If gas is to become the predominant fuel for electric generation, there are many policy and commercial issues that will need to be addressed including can natural gas evolve into a commodity with many of the favorable attributes of coal? With natural gas reaching record levels of utilization for electric generation, the key question before the electric and gas industries is can unconventional gas can be a reliable, affordable and stable fuel for the electric generation fleet, as coal has been for decades? The panelists will address the issues including: those raised in the FERC’s electric-gas coordination regional sessions; pipeline scheduling and infrastructure issues; state regulatory and legislative issues regarding long-term contracting; the alignment or misalignment of gas and electric trading markets; and other issues impacting the increased levels of unconventional gas. These issues will be discussed from the perspectives of producer, pipeline, regulator and end-user utility generator. For additional background, please see http://www.eei.org/ourissues/finance/Special/NatGas_TheNewCoal_CEO-v2.pdf EEI Board Leads: Gale E. Klappa, Chairman, President & CEO, Wisconsin Energy Corporation David M. McClanahan, President & CEO, CenterPoint Energy Inc. Invited Speakers Hon. Phil Moeller, FERC Commissioner (invited) Steve Mueller, President & CEO, Southwestern Energy Company Greg Vesey, President, Chevron Natural Gas Gary Sypolt, EVP and CEO of Dominion Energy, INGAA Chairman CEO Natural Gas Task Force Meeting EEI Fall 2012 Board of Directors and CEO Conference The Broadmoor, Colorado Springs, CO September 13, 2012 SPEAKER BIOS Steven L. Mueller, President and CEO of Southwestern Energy Steve Mueller is the President and Chief Executive Officer of Southwestern Energy Company. He joined the Company in 2008 as President and Chief Operating Officer and was named Chief Executive Officer in May 2009. Mr. Mueller also became a Director of the Company in July 2009. Mr. Mueller has served in multiple operational and managerial roles at Tenneco Oi1 Company, Fina Oil Company, American Exploration Company, BeIco Oil & Gas Company, The Houston Exploration Company and CDX Gas LLC. He serves on the boards of America's Natural Gas Alliance, the American Exploration and Production Council and the Independent Petroleum Association of America. He is also a member of the National Petroleum Council. Mr. Mueller has a degree in geologic engineering from the Colorado School of Mines. Gary L. Sypolt, Executive Vice President, Dominion Resources, Inc. Chief Executive Officer–Dominion Energy Gary L. Sypolt is executive vice president of Dominion Resources, Inc. and chief executive officer of the company’s Dominion Energy operating segment. His responsibilities include oversight of Dominion’s regulated gas transmission pipeline and storage operations, regulated liquefied natural gas operations, Ohio and West Virginia regulated natural gas distribution operations and producer services operations. He joined the company in 1975 and has held numerous management positions at Dominion. Sypolt was president–Dominion Transmission before assuming his current post in June 2009. Sypolt is a member of the boards of directors of several industry associations, including the Southern Gas Association, the American Gas Association and the Interstate Natural Gas Association of America, of which he serves as second vice chair. He is past chairman of the Interstate Natural Gas Association of America Foundation and also serves on the board of the Richmond Forum and the National Advisory Board for Advanced Energy at West Virginia University. Sypolt holds a bachelor’s degree in electrical engineering from West Virginia University. Gregory M. Vesey, President, Chevron Natural Gas Gregory M. Vesey is President of Chevron Natural Gas (CNG) and a Vice President of Chevron Gas and Midstream with responsibility for marketing natural gas to wholesale and large end-use customers throughout North America and contributing to the growth of Chevron’s European gas business. CNG is also responsible for providing competitive and reliable supply and transportation services to company refineries, cogeneration plants, chemical plants and enhanced oil recovery operations. CNG is based in Houston with offices in Calgary and London. Vesey has served as CNG President since early 2011. In 2006 Vesey was named President of Chevron Global Power Company, which manages Chevron's portfolio of commercial power plants and projects in the U.S., Asia, Middle East and Europe and identifies new growth opportunities for power worldwide. Prior to that assignment, he served as President of Chevron Technology Ventures for five years, responsible for creating a portfolio of new opportunities in Chevron's business activities in hydrogen, emerging energy and nanotechnology and Chevron's venture capital investing. Vesey has been a member of the Chevron Management Committee since 2001 and is a member of Chevron’s Gas and Midstream Leadership Team. He also serves as Chevron’s representative to the Natural Gas Supply Association. In addition, he is Chairman of the Board of Directors for Junior Achievement of Southeast Texas and is a Board member of the Alley Theatre. A native of Amityville, New York, he graduated from Northwestern State University in 1980 with a bachelor's degree in business. FERC Electric-Gas Coordination Regional Conferences - Regional Summary New England: •Gas generation comprise large percentage of existing generation; expected to grow •No storage or production •Pipeline capacity constrained •Generators use interruptible pipeline capacity contracts •ISO-NE is proposing changes to its capacity and energy markets to better align with the gas market •Concerns about cost recovery for transportation West: •Gas generation expected to grow •CAISO: generators served by LDC •Generators outside of CA use firm pipeline capacity contracts •CA and Pacific Northwest have storage •Changes needed •Scheduling , additional intra-day flex •Challenges associated with supporting VERs Mid-Atlantic: •Gas generation expected to grow rapidly •NYISO- generators served by LDC •PJM - Generators use interruptible pipeline capacity contracts •PJM – liquid market with pipeline capacity and storage available Central: • Gas generation expected to grow •Some excess pipeline capacity •Generators use interruptible pipeline capacity contracts •Adjustments to the capacity release rules, increased nominations cycles, scheduling over weekends, etc. •Standards of Conduct clarifications needed •MISO concerned about capacity factors on gas fleet and gas availability going forward •Evaluating what changes needed. •Concerns about cost recovery for transportation •Standard of Conduct clarifications needed Southeast: •Gas generation has grown rapidly •Generators use firm pipeline capacity contracts •Long term planning of pipeline needs •Good communication with pipelines •No changes are needed at this time •Concerns expressed about “No-bump” rule Coordination between Natural Gas and Electric Markets Summary - FERC Regional Technical Conferences August 2012 In February, 2011 Commissioner Moeller issued a number of questions for industry comment on several issues related to electric/gas coordination. The request was prompted by the outages in the southwest, as well as the increasing reliance on natural gas for electric generation. EEI filed comments and urged the Commission to discuss the issues on a regional level. FERC held 5 regional forums in August to discuss electric/gas coordination issues. FERC defined the regions as follows:  Central (MISO, SPP, and ERCOT),  Northeast (ISO NE),  Southeast (Southern Company, Duke, TVA and areas south of PJM),  West (Western Interconnection)and  Mid-Atlantic (PJM and NY ISO). In all 5 regions, the roundtable discussions were generally organized around three broad issues: ElectricGas Coordination, Scheduling, and Market Structures/Rules; Communications/Coordination/Information Sharing; and Reliability. Overall, while regional differences were apparent through all the forums, there were discrete areas of agreement. These include:  Pipelines are working with generators to provide services  Generators currently communicate with pipelines and need to be able to continue to do so  Improvements can be made in communications between the two industries as both industries post information but education is needed as to the implications.  The industries can work together to better coordinate maintenance and outages for planning.  Clarification is needed on the FERC Standards of Conduct  Changes are needed to the scheduling and market rules such as changes to the capacity release rules or increasing the number of nomination cycles The following is a high level overview of the discussion in each region on each of the topics as well as next steps: Electric/Gas Coordination, Scheduling and Market Structures and Rules: Participants discussed issues around gas and electric day, natural gas scheduling and commitment practices, electric market rules affecting natural gas procurement and transportation, pipeline services as well as gas infrastructure adequacy. Central Region The participants generally indicated that things are working well; that it is the generators responsibility to ensure supply; and that pipelines are doing a good job of meeting their needs. Most participants agreed that changes to the gas-electric day were not needed but that changes could be made to the capacity release rules and increasing the number of nomination cycles to provide additional flexibility. MISO expressed concerns about the ability to ensure firm gas when it has traditionally not been needed often and the availability of gas as it is used more frequently in the winter. The primary question is how to ensure gas is available when needed when it is not needed 24 hours a day 7 days a week which is the contract for firm pipeline service. EEI Fall Board and Chief Executives Meeting, September 2012 Northeast Region The participants generally indicated that the northeast region faces reliability problems due to lack of pipeline capacity. ISO NE has proposed a number of short and long term market changes which will go through the stakeholder process and filed with FERC in a series of section 205 filings. The proposed changes include moving up scheduling for the day-ahead market and changes to the capacity market. The big question as to how new pipelines will get built and who will pay for it was not discussed in detail. Generators indicated that the costs associated with 24-7 long-term commitment needed to build new pipelines was not recoverable under the current capacity markets and market mitigation rules. Some participants did not agree that moving the day-ahead market would resolve the issue and that it may be useful to determine where the problem areas are prior to taking action Southeast Region The overall impression provided in the forum is that the utilities engage in long-term reliability planning and acquire firm transportation for the natural gas needed for electric generation. Concerns were expressed about the ‘No Bump Rule” and the inability to use firm capacity. Suggestion was also made that increasing the number of nomination schedules may be helpful. West Region The western region is unique in two ways from the other regions. First, unlike the other areas, the primary driver for the use of natural gas is the increasing penetration of variable energy resources and not shale. Second, the issues in the west were defined by three major areas; California, Pacific Northwest and the rest of the west. In California, participants indicated that they there is sufficient pipeline capacity and storage resources that they do not need firm service on the pipeline. Participants in the other states in the Western Interconnection indicated that they generally have firm service on the pipelines and many of the participants in the Pacific Northwest had storage. Concerns were expressed about intra-day swings in the rest of the west. Concerns were also expressed that if there is a wellhead freeze and the producer is not able to deliver then there are no penalties for the producer as they claim force majeure. Mid-Atlantic Region PJM and the NY ISO indicated that they are coordinating a study with ISO NE and MISO, that is currently in the RFP stage, to look at the interaction between the electric and gas industries and that this study will help determine if there are problems and what need to be done going forward. The participants in PJM generally indicated that there is a liquid market and that they pipeline and storage infrastructure were good. Some concern was expressed that as coal plants retire, additional infrastructure will be needed which will not get built in time and that as natural gas is used for peaking, additional nomination cycles would be helpful. New York ISO indicated that they have made changes to allow generators to change their offer in real-time to reflect changing gas prices which allows generators to procure gas intra-day. Most of the generators in New York are behind the LDC and are required to be dual fuel in New York City. The pipelines indicated that while there has been pipeline and storage built in the area it has been funded by producers, which gets the gas to the market but not to the city gate. PJM and NY ISO both indicated that the cost of new entry in their capacity markets does not include the cost of firm transportation. 2 EEI Fall Board and Chief Executives Meeting, September 2012 Communications, Coordination, Information Sharing: Participants discussed communication between the natural gas and electric industries, particularly information sharing practices or protocols in emergency or planned outage situations, as well as the need for standards of conduct in the natural gas industry. Central Region Participants indicated that workshops between the gas and electric industries on how to improve communication may be helpful and that while communication between the generator and pipeline is good, improvements can be made to communication between RTOs and pipelines. The information provided by the RTOs is in the aggregate which pipelines do not find useful. Concerns were expressed about sharing detailed market sensitive information which could be used to manipulate prices. The RTOS do not coordinate outages with the pipelines and rely on generators to communicate that information. Northeast Region The pipelines indicated that they meet to coordinate outages and that they take generator peaks into consideration. ISO NE would like education on what the information posted by pipelines means for supply. Southeast Region The utilities indicated that they communicate with the pipelines daily and try to coordinate outages. West Region The California ISO has made tariff changes to allow then to share more information with pipelines. The utilities in the Pacific Northwest have an agreement to meet twice a year and talk about procedures and processes. The pipelines throughout the west develop their outage schedule and coordinate with their customers and make adjustments as necessary. Mid-Atlantic Region PJM indicated that they are communicating more with pipelines and have started the education process. PJM is also looking into sharing information on the results of the day-ahead market with pipelines and the pipelines posts nomination information. NY ISO indicated that it reviews the information posted by the pipelines to see if they units that have cleared its markets have natural gas and that maintenance coordination is done through information posted by the pipelines and posted by the ISO. The pipelines indicated that their concern with sharing information was that they did not want to give undue preference to a certain group of customers. The pipelines also indicated that it was not possible to predict the impact of a maintenance outage on the secondary or interruptible markets. There was discussion about the need for FERC to clarify its standards of conduct. Reliability: Participants discussed reliability implications of increased use of natural gas for power generation, and any comprehensive assessments or studies that may have been undertaken in the region as well as any emergency response exercises that both industries undertake together. 3 EEI Fall Board and Chief Executives Meeting, September 2012 Central Region Long-term planning does not take pipeline contingencies into account as fuel unavailability is included in the forced outage rate for generators. Pipelines and gas suppliers have not been included in tabletop exercises for emergency planning. Northeast Region NERC indicated, in all the regions, that they would like to see pipeline contingencies incorporated into the planning process. Southeast Region Studies and planning process are done that assume the loss of a pipeline. West Region The utilities in the Pacific Northwest indicated that they are coordinating on emergency preparedness and outside assistance is not necessary. The utilities in the rest of the west indicated that they have limited fuel switching capability due to emission restrictions and that they have some voltage support and frequency issues. There was also discussion of the need to define the risk of the loss of a pipeline for planning purposes e.g. 1 in 10, 1in 20, 1 in 100? Mid –Atlantic Region Most participants expressed a willingness to expand their current table top excurses to include the other industry. FERC expressed concern about having a single source dependency on natural gas. Next Steps: Although FERC has not yet indicated its next steps on electric/gas coordination issues, the discussions in the regions highlighted some of FERC’s concerns:  Possibility of natural gas becoming a single source fuel and its implications  Communication and coordination between the two industries  This is an issue of electric reliability. There was substantial discussion about how the natural gas industry has been reliable and that they are willing to build the level of reliability that people are willing to pay for.  The electric industry needs to look beyond today to see what issues will arise in the future as the demand for natural gas increases. In addition, while the regional forums highlighted the differences between the regions, some areas of commonality emerged around discrete issues of scheduling, communications and standards of conduct. Going forward, it is clear that this is an issue of interest for the Commissioners. It is likely that the Commission will seek comment on issues raised in the forums and on next steps. The question for the industry today is how they would like EEI to proceed on these issues. 4 DISTRIBUTION 2020 EEI Fall Board and Chief Executives Meeting, September 2012 In the second decade of the 21st Century, the electric utility industry is facing transformative technological and economic changes whose effects are increasingly converging at the distribution side of the business as customers begin to have a growing new range of alternative power supply options. As this transformation continues, significant public policy issues will arise including the four major issues outlined below that will be addressed by this panel. The organization of the panel discussion will be as follows: EEI Board Leads: David K. Owens, Executive Vice President, Business Operations, EEI, Introduction, Overview and Framing the Issue Ronald L. Litzinger, President, Southern California Edison, Net Metering Robert C. Rowe, President & CEO, NorthWestern Energy, Utility Participation in DG Markets Richard M. Rosenblum, President & CEO, Hawaiian Electric Company, Distributed Generation Integration Costs Thomas R. Standish, Executive Vice President, CenterPoint Energy, Inc. David Owens, EEI and Robert C. Rowe, NorthWestern Energy, Implementation Plan Accommodating Distributed Energy Resources The electric utility industry understands that its customers have changing needs and desires and, in many cases, want to adopt distributed energy resources (DERs), which may include distributed generation (DG), demand-side management, energy efficiency and conservation, energy storage, and microgrids. In support of these evolving needs and desires, the industry is already making improvements to its infrastructure and operations to accommodate DERs more effectively. Electric utilities also want to ensure that DERs are added to the system in a way that protects reliability, ensures the safety of the public and utility employees, and is fair not only to customers who adopt DERs but also to other customers who may wish to continue to procure power in traditional ways. The increased market penetration of DERs will increase utility costs related to properly integrating those resources, and customers relying on DERs will in most cases continue to rely on the utility grid to back up their own resources. The electric industry wants to ensure that these costs are fairly allocated to those who benefit from the continued needed investment. The following four issues are particularly critical to ensuring that DERs are developed in a reliable, fair and cost-effective manner to the benefit of all utility customers. Distribution 2020 EEI Fall Board and Chief Executives Meeting, September 2012 Net Metering Net metering refers to a state-level policy that encourages distributed generation (DG) by allowing utility customers to offset their electricity consumption via generation of their own electricity. Self-generating, or DG, customers are typically credited at the utility’s full retail rate for the power they produce that offsets their usage of electricity normally delivered by the utility during a billing cycle. In addition, power that DG customers produce in excess of what they need during a billing cycle results in credits at the full retail rate that can be applied against the customer’s bill during later billing cycles when it is not producing enough power to meet its own needs.  Forty-three states and the District of Columbia have net metering programs. Of these 43 states, 14 states also have some form of “virtual net metering,” which essentially allows credits to be applied from a single DG facility to offset electricity consumption at multiple points that do not require a two-way meter (e.g., apartments). Virtual net metering may require the use of distribution and/or transmission systems in new ways, which may add more costs and subsidies.  Net metering programs often operate as part of a broader spectrum of DG incentives including rebates, tax incentives, performance-based incentives and low-cost financing, which may be adopted without full understanding of how they interact and of the overall effects on customers, the electric system and utility operating expenses.  As meter technology has evolved, it is increasingly feasible and cost-effective to use two-way meters that can measure the time of use and production of electricity for DG customers. Many smart meters already have this capability, but traditional dual or separate meters also can be used. Utilities generally went along with net metering when it was small and experimental as a way to encourage new technologies. As various DG technologies become cost-competitive, the reason for the subsidy no longer exists. Now that DG is becoming cost-competitive, it is time to remove subsidies, not to expand them. Significance for Utilities and Customers Net metering shifts costs from DG customers to non-DG customers. This cost shifting occurs because the full retail rate at which the net metering credit is applied to the DG customer includes fixed costs of the utility distribution network—such as wires and customer service costs—that still must be recovered by the utility. In cases where the utility also supplies power to the customer, the fixed costs also include the costs of generating capacity built to serve the customer and that is used to provide backup service. Because DG customers no longer contribute to fixed costs to the extent they meet their own power needs, remaining customers are exposed to higher rates to pay for those fixed costs. A key public policy issue is the potential impact of this hidden subsidy for self-generators on customers who choose not to install DG. Most customers who invest in DG tend to be wealthier than customers who do not invest in DG. Under many net metering programs, wealthier DG customers may not be required to pay their fair share of the costs of the utility distribution system, which threatens to burden lower income customers who cannot afford DG. Net metering errs in treating all DG equally, regardless of its value to the utility system. For example, DG facilities located in areas of a utility system with constrained capacity may reduce congestion on the distribution network and result in utility cost savings. In addition, DG facilities that can generate during a utility’s peak demand periods have more value than DG production during off-peak periods. DG facilities should be paid for their production based on the value of the power provided to the utility, rather than simply because they exist as DG facilities as is the case with net metering. 2 Distribution 2020 EEI Fall Board and Chief Executives Meeting, September 2012 There are more cost-effective ways to encourage DG. Net metering rates are not linked to the cost of the DG technologies being promoted. Usually, effective subsidies are transparent and adjust to the development costs of nascent technologies, paying less as the technologies mature. With net metering, utilities effectively pay more over time because retail rates tend to increase. Policy Issues for Discussion  Should those net metering programs that provide credits at the full retail rate for mature technologies be eliminated? Should DG customers pay for usage at the retail tariff rate based on time of use and be compensated for generation based on the value of that generation at the time it is produced?  Should net metering programs be targeted only at new technologies that have long-term potential but that may need short-term subsidies? Should such net metering programs be limited in scope and have sunset provisions?  Should customers who self-generate continue to pay their share of the fixed costs of the utility distribution grid upon which they rely, even though they reduce their consumption?  What existing utility costs should DG customers be responsible for continuing to pay for as a nonbypassable charge?  What are the rate design and metering and billing options for accomplishing the above objectives? For example, all fixed costs might be recovered through a customer charge paid by all customers connected to the grid, with variable costs recovered through a separate charge that varies with customer usage. In another example, DG customers could be required to pay the full retail rate for all usage, with the utility paying for all power generated by the customer at the applicable wholesale rate in the case of organized markets or avoided cost (as determined by regulators) in the case of traditionally regulated companies. Utility Participation in DER Markets In recent years, there has been an evolving vision of the future electricity industry that entails an increasingly decentralized electric system, with distributed generation (DG), demand response and energy storage supplementing the traditional dependence on large central station power facilities to provide electricity. Numerous state legislative and regulatory policies have been enacted that support this vision, including, in many states, policies that have attempted to create incentives for its realization through the development of distributed energy resources (DERs). In many cases, electric utilities or their affiliates have either been prohibited from or limited in their ability to participate in these emerging markets on the ground that such participation might hinder, rather than augment, market development in the most efficient and cost-effective manner possible. For example, many states prohibit or limit electric utility ownership of DG because of restructuring rules put in place in the late 1990s and early 2000s. Other limitations have been placed on participation of regulated utilities or even unregulated affiliates of utilities in DG markets because of concerns often raised by other DG developers. Other policies have raised indirect barriers to utility participation in DER markets. For example, state tax credits, grants and loans available to third-party owners of DG are sometimes not available to utility owners of DG. There are many potential advantages of utility participation in DER markets, whether through ownership, partnership, or other means. As active participants in DER markets, utilities will not only have an additional avenue for fulfilling their mission of providing reliable and quality electricity service at reasonable cost, but, 3 Distribution 2020 EEI Fall Board and Chief Executives Meeting, September 2012 where they serve as competitive providers of these resources, they also will be promoting innovation and efficiency in their development. While not all utilities may wish to own DG facilities, either through regulated rate base or unregulated affiliates, the ability to participate or partner in both DG and broader DER markets is critical to ensuring that customers have the best options available to them, DG facilities are properly integrated into the grid, reliability of the whole system is maintained, and supply is procured in an optimal way. Significance for Utilities and Customers The participation of utilities in DER markets will increase the number of options available to customers who want to benefit from DER, thereby potentially expanding choice and reducing overall costs. Where they do not already exist, effective safeguards can be put in place to address any concerns about the potential for cross-subsidies between the regulated operations of utilities and possible competitive DER business ventures. Utilities also may be in the best position or only party willing to work with lower income customers who may have an interest in participating in DG. In addition, utility ownership of DG facilities provides a trusted supplier for customers with special needs for backup service at the customer’s site. Utilities are in a position to be good stewards for ratepayers by facilitating the efficient allocation of distributed and other energy resources. Integration is the key to maximizing the performance and cost-effectiveness of DG, and this requires the involvement of the electricity provider. Integrating DG safely, reliably and cost-effectively into the electric utility system is a challenging task, particularly as variable renewable resources become a significant DG resource in many areas of the country. Significant investment and coordination will be required. Utility participation in DG markets and partnership with customers and third-party developers is essential to this process. Utility-owned DG provides an opportunity for utilities to comply with state renewable electricity and energy efficiency resource standards by optimizing supply procurement choices. For states that have renewable electricity standards that include specific requirements for renewable DG, utility ownership and participation in renewable DG facilities may be essential to meeting those requirements. Utility-owned DG provides an opportunity for utilities to diversify resource portfolios with potentially lower cost energy resources. A diverse resource portfolio could enhance the affordability, security and reliability of electricity supply. Policy Issues for Discussion  What should be the role of electric utilities in the development of DER markets? Can utilities play a more effective role than other market agents in such development (in the absence of market barriers that would prevent them from doing so effectively)?  Should state or federal policies that promote the development or interconnection of DG establish a level playing field with respect to the entities that provide them? If utility participation in evolving DG markets is encouraged (recognizing that such participation can advance the public interest), should non-discriminatory access by third-party developers of DG also be ensured?  How can regulators best ensure that rules preventing utilities from unfairly competing in competitive DER markets are reasonable and do not place a burden on utilities such that they would discourage utility entry into DER markets and thus reduce competition? 4 Distribution 2020  EEI Fall Board and Chief Executives Meeting, September 2012 How important is it that utility ownership of DG facilities or other participation in DG markets is voluntary? Should regulators adopt regulations and ratemaking mechanisms that focus on providing an opportunity for all market players to compete, including utilities, rather than policy mandates or incentives that may result in inefficient development of DG, which could result in higher costs for consumers? Backup Rates for Distributed Generation When customers install their own distributed generation (DG) facilities to generate their own electricity, the power output will not always exactly match the needs of the customer. This is especially true for renewable DG facilities, which are variable in nature because their output changes over the course of a day as external factors—such as sunlight or wind—change. Other forms of DG, even those with steady output, are not always available because they may fail (unscheduled outages) or be taken off-line for maintenance (scheduled outages). In all these situations the self-generating customer who wants to keep power flowing must be backed up by another power supplier during those periods when it cannot meet its own needs. If the customer is connected to the grid, this backup (or standby) service is provided automatically. Unless the customer has made other arrangements in advance with its utility (for example, by agreeing to be interrupted) this means that some entity—either the local utility or the customer’s alternative power supplier—must maintain generating capacity to meet the customer’s backup needs. Regardless of who provides backup service, there is a cost incurred by the provider for both maintaining available generating capacity (and not selling it elsewhere) and generating from it when needed to meet self-generating customer backup needs. There are also grid (transmission and distribution) costs incurred in the provision of backup service that must be considered. The rates, terms and conditions for backup service are key determinants of the economic feasibility of DG applications. For this reason, DG developers and self-generating customers typically oppose the imposition of backup rates during regulatory proceedings. They argue that backup rates overcharge them because utilities ignore the benefits provided by DG applications (e.g., deferred or avoided generation, transmission and/or distribution capacity, reduced line losses that naturally occur along distribution and transmission lines, and reduced emissions of pollutants). They also argue that backup rates are discriminatory because they levy charges on DG customers that are different from charges that apply to customers who do not self-generate. Contrary to these claims, utilities often cannot defer or avoid generation due to the unreliable nature of variable DG technologies. In fact, DG often triggers distribution and/or transmission upgrades as opposed to deferring them. Additionally, DG developers are often provided numerous carve-outs and subsidies that are not available to other systems. Lastly, backup rates are often embedded in rates of customers who do not self-generate and do not represent discriminatory charges. Despite these facts, regulators have sometimes been sympathetic to DG developer pleadings. Some states have exempted self-generators from backup service charges based on varying criteria. Other states have set backup rates in a manner that does not enable the utility provider to recover the full costs of providing the service. 5 Distribution 2020 EEI Fall Board and Chief Executives Meeting, September 2012 Significance for Utilities and Customers Failure to recover the costs of backup service from self-generating customers who rely on backup service shifts costs to other customers. Backup costs that are prudently incurred on behalf of self-generating customers must be recovered by the utility. As DG applications grow, state policies that deny full recovery by utilities of the costs of backup service from self-generating customers will expose other customers to higher rates to pay for those costs. This hidden subsidy for self-generators unfairly burdens customers who do not self-generate, including lower income customers who cannot afford to install their own generation or customers who do not use a lot of energy and therefore are not inclined to install DG. Implicit in the need to adequately compensate providers of backup service is a recognition of the role such service plays in enhancing the value of the DG itself. Utilities provide value to DG customers by being ready to stand behind those customers and making continuing investments to enable DG market penetration. To accommodate the growth of DG on their systems, utilities must continue to make investments in distribution systems, backup power sources, and modernizing the grid. If utilities were not making these investments, and thus maintaining the capability to provide backup services, DG customers would have to go elsewhere for these services, probably at a much higher cost. These investments thus provide direct benefits to DG customers and reduce the costs of DG installations. Failure to recover actual backup costs from self-generating customers who rely on backup service hides the true costs of DG applications. Rate exemptions or rates that do not adequately compensate the utility for providing backup service may encourage DG applications that are not economically efficient. This means that other, more efficient options for the customer may be lost. Moreover, when these customers face higher than necessary rates from their current supplier, they may be encouraged to make uneconomic decisions to self-generate—resulting in even further subsidies from other customers. Choices to self-generate should not be made at the expense of other customers based on faulty economics. Usually, effective subsidies are transparent and adjust to the cost developments of nascent technologies, paying less as the technologies mature. The amount of the subsidy provided to self-generating customers through backup rate exemptions or rates that are not fully compensatory is not transparent, which makes it hard for policymakers to make informed decisions. As various DG technologies become cost-competitive, the reason for the subsidy no longer exists. Now that DG is becoming cost-competitive, it is time to remove subsidies, not to expand them. Policy Issues for Discussion  Should DG customers pay the full cost of backup service incurred to provide the service to avoid any subsidies, hidden costs, and inefficient price signals for power supply decisions? Is this true in all cases?  What is the fair share of other costs that should be paid by DG customers, such as the costs of distribution system upgrades to accommodate DG safely and reliably, and dedicated metering and billing enhancements?  Recognizing that there is no one rate design for recovering the costs of backup service from DG customers, what are the best options that regulators should consider (depending on circumstances in their state such as the business models of their regulated utilities)? Examples include some combination of four basic charges, as follows: 1. Customer charge to recover fixed costs related to customer care and the customer’s portion of distribution facilities. 6 Distribution 2020 EEI Fall Board and Chief Executives Meeting, September 2012 2. Reservation charge to recover the customer’s portion of costs incurred to hold generating capacity available for backup service when needed. This charge may be calculated as a function of the outage rate of distributed generators on the system, the outage rate of the utility’s generators, and the utility’s required reserve margin. 3. Demand charge to recover the customer’s portion of generating capacity costs actually incurred to generate power. 4. Energy charge to recover the variable costs (largely fuel) incurred to generate backup power. Which of these types of charges for backup service are applicable to different market structures and circumstances? Are there any others? Recovering Integration Costs for Distributed Generation Current electric utility distribution systems were by and large designed to move power from transmission substations, where power is collected from large central station generators, in one direction through communities and neighborhoods to individual homes and businesses. Today, however, the distribution system is being called upon to absorb power generated at customer locations that is fed into the distribution system—so-called distributed generation (DG). The distribution system is usually able to handle a small amount of DG without causing safety or reliability problems for the utility. As DG market penetration increases, the problems created by this two-way flow of power on distribution systems intensify. The utility must incur additional costs to accommodate these new power sources so that it can continue to operate the system without overloading circuits, causing voltage regulation and power quality problems, or jeopardizing the safety of utility workers and the public. The problem is exacerbated by the fact that many DG sources—wind and solar photovoltaic (PV) technology in particular—are variable in nature, so that the utility must accommodate fluctuating levels of generation from what could become a significant number of these resources in its service territory. The additional costs incurred by the utility to accommodate growing sources of DG are referred to as integration costs. These costs are generally associated with utility system upgrades, deployment and availability of other power supply sources that can pick up customer load when DG is not operating, and deployment of new grid modernization technologies for distribution system automation and control. Such costs can and will become significant as DG increases its presence in the market. The impacts will be seen not only on individual circuits but also increasingly at substations and ultimately at the regional subtransmission and bulk transmission levels as DG penetration grows over time in many regions. DG also can potentially provide system benefits such as reduced production costs, reduced losses of electricity flowing on the distribution system, deferred capital improvements, and greater fuel diversity. Any such benefits must be evaluated and compared against incremental integration and other DG deployment costs to determine the overall benefits and costs of DG and how those savings and costs should be allocated to both DG and non-DG customers. 7 Distribution 2020 EEI Fall Board and Chief Executives Meeting, September 2012 Significance for Utilities and Customers Failure to recover the appropriate share of DG integration costs from DG customers shifts costs to non-DG customers. Integration costs that are prudently incurred on behalf of DG customers must be recovered by the utility. As DG applications grow, policies that deny recovery by utilities of the appropriate share of integration costs from DG customers will expose other customers to higher rates to pay for those costs. As with other hidden subsidies for DG, such as those found in many state net metering and backup service policies, this approach unfairly burdens customers who do not install DG, including lower income customers who cannot afford to install their own generation and customers who do not use a lot of energy and therefore are not inclined to install DG. While the initial costs of integration may be fairly visible, the system-wide integration costs that may occur later often are not readily apparent at first and may dwarf the initially defined costs. As described above, identification of all costs caused by DG integration cannot be completely known in advance because the scale is dependent on the level of DG market penetration—particularly with respect to the system-wide grid modernization costs. Regulators and policymakers should be aware that these costs, which may be initially hidden from view, exist and may have significant customer impacts down the road. Utilities can balance these competing dynamics by ensuring detailed studies are requirements of their interconnection processes while also allowing waivers for these studies for small DG customers. Failure to recover the appropriate share of integration costs from DG customers hides the true costs of DG applications. Rates that fail to recover the appropriate share of integration costs from DG customers may encourage DG applications that are not economically efficient, which potentially raises the total cost for all customers. Customers may be encouraged to install DG simply because the real costs are subsidized by other customers. This means that other, more efficient options for the customer may be lost, and other customers facing higher than necessary rates from their current supplier may be themselves encouraged to make uneconomic decisions to self-generate. Policy Issues for Discussion  How can utilities ensure that all integration costs, whether immediate or not and whether associated with particular facilities or not, are identified and properly considered in the ratemaking process?  Which integration costs should be paid entirely by the DG customer, and which might be considered joint and common costs that are beneficial to all customers and for which all customers should pay an appropriate share?  What principles and methods are needed to address the allocation of costs identified as joint and common?  Should DG interconnection service rules or tariffs be modified so that the appropriate share of fixed and variable costs, as can be reasonably identified and allocated, are recovered through corresponding fixed and variable service charges paid by DG customers connected to the grid? Are there other ways to ensure that non-DG customers do not end up paying for costs appropriately borne by DG customers? 8 Facing The Challenges of A Distribution System In Transition David K. Owens Executive Vice President, Business Operations Framing The Transition Issue  Retail customers are gaining a wide range of new power supply options including distributed generation, energy storage, demand response and microgrids—transforming the distribution system  While the electric utility industry supports the desire of its customers to adopt distributed energy resources (DER), we also want to ensure that DERs are added to the system in a way that protects reliability, ensures the safety of the public and utility employees and is fair to all customers  Regulatory agencies and legislatures are promoting policies that are accelerating this transition—subsidies are growing 2 Framing The Transition Issue  Transition creates new challenges for utilities:  Prospect of declining retail sales and earnings  Financing of major investments in the T&D system; workforce issues  Potential obsolescence of existing business and regulatory models  Challenge: How do you grow earnings in this environment? 3 What’s Encouraging Distributed Generation?  29 state plus D.C. have RPS programs, 17 with mandates/programs for solar and other DG  Net metering programs – present in 43 states  Feed-In Tariffs – adopted or proposed in a few states  Virtual net metering – present in 14 states  Subsidies, rebates, tax incentives, financing incentives. California provides $1.9 Billion in solar subsidies over 10 years  Zero net energy goals and targets, microgrids 4 What’s Encouraging Distributed Generation?  DOD, the largest energy user in the US, is actively seeking to implement renewables, “islanding” policies, and virtual net metering.  Higher retail electric rates improving economics of DG  Technology advances in power electronics, energy storage, sensing and measurement, controls, etc. are improving the reliability and economics of DG 5 Growth of Distributed Generation Will Increase Required Distribution Investment  Current infrastructure, essentially a one-way system, will have to be redesigned to accommodate bi-directional and variable power flows safely and reliably. This is much more complex to operate and control  Changes will be required in:  Physical Infrastructure  Operating Systems  Risk Management, including Cyber-security.  Coordination with Transmission and Generation systems  Technological obsolescence of existing infrastructure will become an increasing challenge 6 What are the Challenges and Obstacles for Fairness?  Hidden subsidies like net metering allow higher income customers to avoid system costs, which are then paid by middle and lower income customers  Loss of customers. California reported over 1,000 MW and over 104,000 solar projects at the end of 2011.  Under net metering, such projects pay little distribution or other fixed costs, despite the fact they impose new costs on the system  Competition. Third parties owned 72% of residential solar systems and over one-quarter of non-residential solar systems installed in 2012 (through May 27) in California 7 What are the Challenges and Obstacles for Fairness? (cont’d)  While we do support the desire of our customers to adopt distributed energy resources (DER), we also need to ensure that DERs are added to the system in a way that protects reliability, ensures the safety of the public and utility employees and is fair to all customers 8 Conclusions  The grid will need to undergo major investments as a result of:  Reliability improvements  DG and renewables integration  Grid modernization  All customers who benefit from such investments should pay their appropriate share of the costs to upgrade the system  DG/renewable integration costs, and standby and back-up costs, will become significant as DG penetration increases. Such costs must be transparent and shared by customers who benefit from DG 9 Conclusions (Cont’d)  Rate increases to recover these costs must be acceptable to customers and regulators, but moderation in fuel costs may help mitigate the impact of higher distribution rates.  Industry must develop an action plan to address the challenges and obstacles to fairness. 10 Four Critical Policy Issues Of Immediate Concern  Today’s panel will address four critical policy issues related to the transition of the distribution system that are of immediate concern:  Net Metering  Prohibitions On Utility Participation in DER Markets  Distributed Generation Integration Costs  Backup Rates  At the conclusion of the discussion, we will discuss a proposed action plan designed to address our concerns over these issues 11 Action Plan  Focus outreach activities on three target groups:  Customers  State Legislators/Governors  Regulators/Consumer Advocates 12 Customers  Target relevant customer segments  Identify regulatory changes needed for utilities to deal with changing business environments  Outreach via EEI National Key Accounts Program  Build customer concerns about net-metering, cross-subsidization  Gain support for utility involvement in DG, microgrid space  Promote fleet and off-road transportation applications  DataCenters (DC)  Incorporate multi-site DC companies into National Key Accounts Program  Provide members with DC market activities, best practices, competitive intelligence  Department of Defense  Siting utility-owned generation on DoD land  Expand Utility Energy Services Contracts, privatization initiatives 13 State Legislators/Governors  Promote policies to remove barriers for utilities pursuing distributed generation  Partner with stakeholders - environmental groups, national associations, distributed resource developers  Outreach and education at the state level regarding the impacts of subsidies on customers 14 Regulators/Consumer Advocates  Support policies that avoid undue subsidies for DG customers, thus mitigating rate increases to non-DG customers  Promote regulation that supports investment in grid system upgrades.  Reliability improvements  DG and renewables integration  Grid modernization  Ongoing education and outreach to regulators and consumer advocates  NARUC/NASUCA/Other Consumer Groups  Gee Strategies – Dialogue with Wall Street leaders, regulators, advocates and utilities  Critical Consumer Issues Forum (CCIF) 15 Critical Consumer Issues Forum (CCIF)  Dialogue for State Commissioners, Consumer Advocates and EEI Member Companies  To date CCIF has included 39 Commissioners; 35 consumer advocates (incl. NASUCA, AARP, Consumers Union, NCLC & Public Citizen); and 33 IOU reps  Value Proposition  Candid dialogue & info exchange in non-adversarial setting  Increased trust and credibility; strengthened relationships  Unique collaborative process adaptable to many future topics 16 CCIF Feedback “…We were able to highlight the specific challenges arising from the multitude of “high priority” concerns on the table today for consumers, utilities and regulators, and the need for ways to prioritize resolution of issues competing for our attention. Paula Carmody, NASUCA President “CCIF has proven to be invaluable. The candid dialogues with utility and consumer representatives on issues of importance to their constituents back home also have added depth and perspective to the ongoing discussions NARUC continues to hold with a wide variety of federal agencies . . . ” Tony Clark, Former NARUC President 17 CCIF Feedback “WHEREAS, To the same ends, NARUC Commissioners have also participated in a series of valuable Critical Consumer Issues Forum (CCIF) meetings with consumer advocates and utility representatives. These meetings have been valuable in facilitating communications and a better understanding of the interests and concerns of the stakeholders; the CCIF collaboration should continue; and” NARUC Resolution on Smart Grid Principles, Adopted July 20, 2011 18 C HALLENGES IN THE BULK ELECTRIC SYSTEM EEI Fall Board and Chief Executives Meeting, September 2012 The U.S. bulk electric power system is now facing a number of significant challenges as we continue the complex transition to a system that relies increasingly on natural gas, renewable energy and demand response to meet load requirements. These changes are primarily a function of historically low natural gas prices (stimulated by the current abundance of shale natural gas), state renewable portfolio standards, along with artificially high regulatory incentives for encouraging a substantial increase in demand response. At the same time, our industry is facing significant challenges in the area of infrastructure enhancement and the capital expenditures necessary to support that. This segment of the Board will explore these rapidly evolving dynamics and address industry efforts to enhance aging infrastructure while also growing revenue and earnings. EEI Board Leads: Anthony J. Alexander, President & CEO, FirstEnergy Corp., Demand Response Gerard M. Anderson, Chairman, President & CEO, DTE Energy, State Portfolio Standards Benjamin Fowke, III, Chairman, President & CEO, Xcel Energy, Infrastructure/Capital Expenditures Facing The Challenges of a Bulk Electric System in Transition EEI Board and CEO Meetings September 12-14, 2012 Colorado Springs, CO Framing The Transition Issue  There are a wide range of new power supply options which are transforming the bulk electric system.  Lower prices of natural gas largely due to non-conventional sources such as shale gas, are putting downward pressure on wholesale electricity prices and providing viable options for utilities switching from coal.  Wholesale demand response is helping to avoid the construction of new power supply facilities, and in some regions such as PJM, prices for demand response have stimulated a surge in this resource.  Unproven resource during critical system load situations  Disrupting capacity markets  Renewable technologies are increasingly contributing to wholesale energy supply aided by renewable portfolio standards in 29 states and tax incentives.  These are variable sources with interconnection and integration challenges 2 Framing The Transition Issue  Transition creates new challenges for utilities:  Prospect of declining sales and earnings  Financing of major investments in the T&D system; workforce issues  Potential obsolescence of existing business and regulatory models  Challenge: How do you grow earnings and enhance infrastructure in this environment? 3 DR Participation in PJM Capacity Market Source: PJM 2014/2015 Base Residual Auction Report. Reflects DR that participated but may not have cleared 4 Cleared in PJM Capacity h?arkets 2010 - 2011 939.0 2011?2012 1,364.9 2012?2013 7,047.3 568.9 2013-2014 92819 679.4 2014-2015 14, 228.4 882.1 2015?2016 14,8328 922.5 State RES Policies WA: 15% by 2020 MT: 15% by 2015 OR: 25% by 2025 (large utilities) ND: 10% by 2015 SD: 10% by 2015 NV: 25% by 2025 MN: 25% by 2025 (Xcel: WI: 10% 30% by by 2015 2020) NE: 10% by 2020 (public power districts) UT: 20% by 2025 CO: 30% by 2020 (IOUs) CA: 33% by 2020 AZ: 15% by 2025 NM: 20% by 2020 (IOUs) MI*: 10% & 1,100 MW by 2015 NY: 29% by 2015 IA 105 MW KS: 20% by 2020 OH: 12.5% by 2024 IL: 25% by 2025 IN: 10% by 2025 MO: 15% by 2021 PA: 18% by 2021 VA: 15% by 2025 NC: 12.5% by 2021 (IOUs) OK: 15% by 2015 AK: 50% by 2025 TX: 5,880 MW by 2015) HI: 40% by 2030 FL: Solar pilot 2010-2014 LA: 350 MW by 2012-13 Renewable electricity standard Renewable electricity goal Pilot or study * Michigan: A referendum will take place in Nov. 2012 on a 25% by 2025 RPS. Source: www.dsireusa.org; Federal Energy Regulatory Commission ME: 30% by 2000 (10% new by 2017) NH: 24.8 %by 2025 VT: 20% by 2017 MA: 22.1% by 2020 RI: 16% by 2020 CT: 27% by 2020 NJ: 20.38% by 2021 + 5,316 Gwh solar by 2026 DE: 25% by 2026 MD: 20% by 2022 DC: 20% by 2020 WV: 25% by 2025 Industry Capital Expenditures Source: EEI Finance Department, company reports, SNL Financial (August 2012) 7 Drivers of Elevated 2012 CapEx  Projected spending for 2012 has increased more than 10% from previous projections  Accelerations of various capital projects  Higher volume of near-term renewables projects (primarily solar and wind)  Expended range of projects related to environment compliance *Projection for 2012 is $94.4 billion currently, was $85.0 billion as of August 2011 8 Projected Functional CapEx 2010P as of August E?l? $32.3 BI 2012P es of Augu 5t 2:112 1WD I Generation I Distribution lTransmission I Ge s-Releted I Environment I Dther Rate Case Volume Remains High Number of Rate Cases Filed 19138 1:199 2000 2001 2002 2003 20m. 200-; 2006 200? 2008 200:] 2010 2011 10 US Electric IOUs Rating History 000 Credit Ratings Distribution, U5. Shareholder-Owned Electric Utilities 10000 2 9" EDIE) 0000 50% 4000 20 +0 35%] 0% 000 10?0 1000 1000 2000 2011 0.00 I 00+,00, 00.? I I 000+, 000 I 000? I 00+, 00, 00?, 0, 000+ Source: Standard Poor?s Macquarie Capital 11 FERC’s Vision “I have a vision for the future where energy efficiency, demand response, micro-generation, combine heat and power, and other distributed resources are the first source of energy services for most consumers. And those distributed resources are fully supplemented with competitive procurement of large-scale wind, solar, hydro, geothermal, and other renewable resources rounding out a significant share of total energy resource mix for North America.” John Wellinghoff Chair Federal Energy Regulatory Commission 12 ALAN SIMPSON BIOGRAPHY EEI Fall Board and Chief Executives Meeting, September 2012 In a career hallmarked by a fearlessness of confronting the most intractable issues of our times, Alan Simpson served as the co-chair of the National Commission on Fiscal Responsibility and Reform, a bi-partisan group looking to erase the United States’ multi-trillion dollar debt. Describing himself as someone who hates hypocrisy and pretense and has the temerity to say so, this is only the latest challenge taken on by Simpson who is best known for being a forceful voice for common-sense policy throughout his nearly two decades in the Senate. With quick wit and a straightforward style, Simpson tackles the most controversial of topics on the national agenda—bringing both honesty and sensible solutions for moving the country forward in these most uncertain of political times. Formerly a visiting lecturer in Political Science at the University of Wyoming—his alma mater—and formerly the director of the Institute of Politics at Harvard’s Kennedy School of Government, Simpson provides audiences with anecdotes, humor and cutting-edge commentary on politics, the media, Social Security and Medicare/Medicaid reform, the economy and much more. He enjoys taking questions from any audience. Source: Washington Speakers Bureau STORM RESILIENCY /RESPONSE EEI Fall Board and Chief Executives Meeting, September 2012 Our industry’s response to hurricanes, ice storms and other severe weather events has become a subject of sharply escalating public focus in the past few years. Hurricane Irene in 2011 and the more recent “derecho” that battered the Midwest and Mid-Atlantic in June precipitated debate about industry restoration times that continues today. The ever-increasing electrification of U.S. society, coupled with our dependence on “alwayson” technologies, has sharply elevated customer expectation about restoration time frames and diminished patience and understanding of the complex tasks at hand when recovering from major storm events. This segment of the Board meeting will discuss the changing dynamics of public perception about storm recovery and explore a range of options under consideration in which our industry can “change the conversation” about power restoration when it comes to customers, regulators and other stakeholders. EEI Board Leads: Joseph M. Rigby, Chairman, President & CEO, Pepco Holdings, Inc. Other CEOs whose service territories have been affected by recent major storms Maryland Undergrounding Roundtable Written Statement of James P. Fama, Vice President Energy Delivery, Edison Electric Institute August 27, 2012 Good afternoon, I am James P. Fama, Vice President, Energy Delivery for Edison Electric Institute. EEI is the association of US. shareholder-owned electric utilities. Our members serve 95% of the ultimate customers in the shareholder?owned segment of the industry and represent approximately 70% of the US. electric power industry. Thank you for the opportunity to participate in this roundtable. I will offer some brief opening remarks. The Pros and Cons Of Undergrounding Over the years there have been many studies of undergrounding electric distribution lines. These studies show that undergrounding comes with many benefits but also presents several challenges. The most apparent benefit is the reduction in disruptions due to weather and vegetation. As we all know, vegetation is one of the leading causes of outages. Coupled with extreme weather, tree limbs and fallen trunks present the most imminent danger of outages. In dense urban areas, construction of underground lines is preferable where the logistics of overhead lines are impractical. Some aSpects of maintenance are easier to manage as the facilities remain at ground level without necessitating poles and bucket trucks. Finally, the aesthetics of underground lines are more pleasing to the public and customers tend to be more accepting of these projects rather than new poles and lines altering or obstructing views. IIPage However, undergrounding does pose significant challenges as well. Although undergrounding lines diminishes the harm caused by storms, ?ooding and uprooted trees can pose an outage threat to underground cables. Repair times and restoration generally take longer for underground cables with diagnostics becoming more complicated as linemen can no longer rely on visual inspection to locate and diagnose problems on the line. Underground facilities tend to be less ?exible than overhead facilities when making upgrades or other system changes Underground systems are still vulnerable to lightning and equipment failure. The Cost Associated With Undergrounding The biggest hurdle associated with undergrounding is its high cost. Costs for materials, construction, installation, replacement, and operation and maintenance of underground lines are all higher than that for overhead lines. A 2008 EEI study showed that construction of new overhead distribution lines ranges from $53,000 (rural) to $386,000 (urban) per mile. Construction of new underground distribution lines is considerably higher, ranging from $63,000 (rural) to $2 million (urban). The study also showed that the cost of converting overhead lines to underground could be significant, ranging from $80,000 (rural) to $2 million (urban). However, the costs of conversion could range even higher, especially in larger urban areas, as the 2008 study is now four years old and furthermore utilized projections from utilities in low cost rural areas and mid-sized urban areas. What States Have Done Over the years, a number of states have commissioned studies to assess the viability and costs of undergrounding. The general consensus has been that converting existing overhead facilities to underground facilities is cost prohibitive compared to the benefits gained in terms of reliability. However, some states require utilities to underground lines in new residential 21Page subdivisions, which is becoming the industry norm. Some States have provided incremental cost recovery mechanisms in utility tariffs for customers that specifically request undergrounding of lines. While a widespread conversion of the existing overhead infrastructure to underground facilities would be cost prohibitive, there is increasing support for ?selective undergrounding.? Some states have ?selected? new residential and commercial distribution to be underground, absent exceptional circumstances. As earth?moving is already underway and disruption is minimal, undergrounding makes the most sense. Urban areas have also seen an increase in the use of undergrounding as a reliable option when overhead wires are not feasible. Priority for undergrounding is also being given to critical facilities when excavation is already underway in cases of sewer, water main, or roadbed replacement. Increasingly, states are providing consumers with the option to request undergrounding with varying mechanisms to collect the incremental costs. Going forward, utilities should evaluate their distribution networks to identify which structures have been most prone to outages and have proven more difficult to harden as possible candidates for selective undergrounding. The Relative Cost-Effectiveness Of Undergrounding There are a broad range of options for increasing distribution reliability, which can be divided into two broad categories: infrastructure hardening and resiliency measure. A hardening option would be a measure designed to strengthen your system to avoid an outage in the first place. Examples would include undergrounding or poles built to a higher design standard. A resiliency option would be a measure designed to shorten restoration time after an outage. Examples would include increasing the number of available crews or maintaining more spare equipment and materials. 3 Page All options, whether they fall into the hardening or resiliency categories, have their particular costs and their particular degree of effectiveness. For example, stronger poles may be cost effective and signi?cantly increase reliability in Florida where hurricane winds can be strong. In contrast, undergrounding may be less effective when looking at cost and reliability in Florida because of the high water table and potential for ?ooding. Electric customers are best served by a careful evaluation of the relative cost-effectiveness and reliability impact of the wide range of options, including undergrounding, with a goal of optimizing the mix of hardening and resiliency measures. 4 Page Maryland Undergrounding Roundtable Recommendations of James P. Fama, Vice President Energy Delivery, Edison Electric Institute Short term: 0 Evaluate the relative cost-effectiveness of selective 'undergrounding against (1) other hardening options, and (2) resiliency options (shortening restoration times). 0 After determining cost-effectiveness, undertake selective undergrounding of outage- prone overhead lines that have proven difficult or impossible to harden in other ways. 0 Evaluate and implement mechanisms for cost recovery of selective undergrounding. Long term: - Evaluate more extensive undergroundng as well as new and evolving technologies for their relative cost?effectiveness, taking into account the costs of more extensive undergrounding and integrating new technology with the distribution system. 0 Evaluate the effect on reliability of more extensive undergrounding and integrating new technologies with the distribution system. 0 Evaluate and implement appropriate mechanisms for cost recovery of more extensive undergrounding and new technologies. CYBERSECURITY EEI Fall Board and Chief Executives Meeting, September 2012 The Edison Electric Institute recognizes the cybersecurity challenge as an imperative to provide leadership in the areas of prevention, response and recovery. As an association, we are working aggressively to coordinate an industry response to emerging threats associated with cybersecurity by working with the Chertoff Group in compiling the Threat Scenario Project. By helping organizations identify risks, the Chertoff Group assists in building a framework and developing effective policies to prevent cybersecurity incidents. EEI also recently met with the Knowledge Consulting Group—a cybersecurity services firm that works with the CIA, Department of Homeland Security, and the Justice Department—to discuss key technical elements of response and recovery. One outcome of that work will be the creation of a Cybersecurity Event Response Plan template to assist members. The goal of this plan is to outline the necessary actions to facilitate a successful response and restoration in the event of cyber incident. The plan will provide member companies with basic guidelines, procedures, contact information and other resources. The plan also is designed to be flexible and can be customized to meet an individual company’s needs in countering specific cyber threats. EEI is also working to provide a tabletop exercise template that members can use to simulate a cyber event. The tabletop simulation will provide an opportunity to improve preparation of the response plan. EEI Board Lead: James P. Torgerson, President & CEO, UIL Holdings Corp. August 24, 2012 The Honorable Steven Chu Secretary, Department of Energy 1000 Independence Ave., SW Washington, DC 20585 The Honorable Janet Napolitano Secretary, Department of Homeland Security Nebraska Ave. Center, NW Washington, DC 20528 Dear Secretaries Chu and Napolitano: We write today to thank you for the very productive meeting on July 23 that stemmed from the National Infrastructure Advisory Council (NIAC) report on electric and nuclear sector resilience. We appreciate the recognition that an ongoing, high-level dialogue between the government and the electric power sector— investor-owned, municipals, cooperatives and nuclear—is invaluable when it comes to protecting critical infrastructure. As trade associations representing nearly every electric utility and nuclear generator in the United States we understand that, in times of crisis, close coordination and preparation with the government—and with each other—is imperative. Critical infrastructure protection is a shared cause that demands planning, as well as an understanding of roles and responsibilities ahead of time. Based on the discussion last month, we are confident the framework is in place for just such coordination. To build on that framework and take tangible steps toward further protecting the nation’s electric power sector, we are eager to work together and take advantage of the momentum generated by the NIAC meeting. Below are a few of the next steps discussed at the meeting that could be acted upon quickly and could immediately benefit national security:  Expedited clearances for industry leaders representing the four segments of the industry: Industry executives and the four trade association CEOs are uniquely able to inform government decisions while also representing colleagues throughout the sector. To be effective, this requires information that comes from high-level secured briefings.  Cleared briefing for CEOs: In 2008 the government provided a cleared briefing for a select group of industry CEOs; this was invaluable as it provided insight into national security concerns facing the industry which has informed our decision making ever since. We stand ready to make representatives from all four segments of the industry available so the government can, once again, inform industry leaders with the most current threat information.  Follow-up meeting with Secretaries: A follow-up to the July 23 meeting that further clarifies next steps and ensures progress continues to be made would be invaluable. To this end, a meeting later in the fall with representatives of all four utility associations was discussed. This would provide an opportunity for a deeper briefing in a smaller setting, and allow for a discussion on next steps going forward.  Formation of working groups: The framework for ongoing collaboration will be the working groups we discussed. We suggest a group of CEOs from across the industry to work with the Secretaries to provide leadership and ongoing strategic guidance for the industry and the government. We also suggest a subgroup with industry and government experts to focus on recovery and response initiatives to inform postdisaster decision making before a disaster happens. We understand our staffs have already been working together on these initiatives; we appreciate your leadership and share your sense of urgency. As such, we stand ready to provide the resources necessary to support these endeavors and to ensure this partnership is successful. It is noteworthy that so many stakeholders of the electric power industry have banded together despite disparate membership and occasionally-competing policy goals. In fact, given that the electric grid is essentially one machine with multiple owners, users and operators, we have found common cause to work together to secure and protect this critical infrastructure. The electric utility coalition welcomes this collaboration with government partners and believes the industry’s experience working together on these issues can serve as a model as you work to secure other critical sectors. Thank you again. We look forward to working together in a partnership that results in informed decision making to protect the grid and allows a well-coordinated response to protect our national interests. Sincerely, _______________________________ __________________________________ Mark Crisson, CEO American Public Power Association Thomas R. Kuhn, President Edison Electric Institute _______________________________ ___________________________________ Glenn English, CEO National Rural Electric Cooperative Association Marvin S. Fertel, CEO Nuclear Energy Institute EDWARD MARKEY 2108 RAYBUHN HOUSE OFFICE BUILDING WASHINGTON. DC 20515?2107 NATURAL RESOURCES i202) 225?2836 DISTRICT OFFICES: at the ?ttm?teh ?tatta awe vi teammate Washington. that 20515?2107 {508} 8713?2900 August 8, 2012 The Honorable Barack Obama President 1600 Avenue Washington, DC 20500 Dear Mr. President, American?s electricity grid is the linchpin of American economic and national security. All of our Nation?s critical systems ?nancial services, health care, telecommunications, transportation, water, defense, law enforcement depend on the electricity grid. Despite years of thorough investigation and exhaustive hearings in both the House and Senate, it became clear last week that Republicans in Congress will not allow the passage of badly needed legislation to addresses the cyber threats to America?s electrical grid. I write today to strongly urge you to take action by executive order to ensure that all necessary measures be taken to secure system reliability when cyber threats and vulnerabilities to the nation?s electrical power system are known. It is unconscionable that Congress has failed to take decisive legislative action to address what should be a non-partisan national security issue. In the last Congress, I, along with Republican Congressman Fred Upton, introduced the GRID Act, which gives FERC the clear authority to issue regulations to combat known cyber?vulnerabilities. That way, we need not be at the mercy of an industry that historically has been inexcusably slow to act. The legislation passed by a vote of 47?0 in Committee and unanimously in the full House of Representatives. The electric utility industry then successfully persuaded Senate RepubliCans to stall the bill. In this Congress, emboldened by the drumbeat of regulatory repeal that has been the hallmark of the new Republican majority, the electric utility sector has lobbied aggressively against the measure. House Republicans have acceded to industry?s desire to simply regulate itself. From banks to hospitals to police, none of our core public or private institutions can properly function without the grid. Ninety?nine percent of the electric energy used to power our military facilities including critical strategic command assets comes from the commercially operated grid. Our dependence on the grid is only deepening as we move towards greater reliance on automation and information technology. A coordinated attack by sophisticated cyber criminals has the potential to knock out all of these systems for weeks or months or even years. National security experts have warned of an intensifying terrorist threat to America?s critical infrastructure. FBI Director Robert Mueller recently warned that cyber-attacks soon will surpass terrorism as the number one threat facing the country. The Department of Homeland PRINTED ON RECYCLED President Obama Page 2 August 8, 2012 Security has warned that hackers have come close to shutting down portions of our critical infrastructure. Reports of cyber?security incidents at U.S. power plants'and other infrastructure skyrocketed nearly 400 percent from 2010 to 201 1. And all ?ve Federal Energy Regulatory Commissioners (FERC), the agency with jurisdiction over electrical facilities, have stated in Congressional testimony that they ranked cyber-threats at the very top of their list of threats to electricity reliability. Regrettably, the utility industry is not doing what it should to combat these threats, and FERC currently lacks the authority to compel it to. As you know, FERC directs the electric utility industry to suggest its own standards to combat cyber-security vulnerabilities. However, there are no hard and fast deadlines with this voluntary approach, and if the industry proposes inadequate measures, all FERC can do is remand the measures for further work. Finalizing reliability standards through this industry?led, consensus-based process typically takes years. It is wholly inadequate for responding to time sensitive threats and vulnerabilities related to infrastructure that is critical to national security. It took the industry several years to ?nish writing voluntary recommendations to combat the 2007 ?Aurora vulnerability,? which could cause key portions of power-plants to self-destruct. Industry has done little to assess the effectiveness of these voluntary measures and has not submitted a single one of them to FERC in the form of a proposed mandatory standard. In 2010, industry issued 12 voluntaiy recommendations to combat the Stuxnet computer worm, which was used to attack Iran?s nuclear centrifuges and which has since been re?designed so it can harm other systems. But industry only agreed to turn ?ve of the 12 recommendations into mandatory standards. And when the FBI warned in 2010 that cyber?intruders could remotely gain access to electric utility assets, an industry vote rejected the majority of their voluntary recommendations be made mandatory. Leaving America powerless against the threat to the security of our electricity grid is an unacceptable and an unnecessary risk. We should not wait for a crippling terrorist attack on our grid before we act. If Congressional Republicans insist on fully entrusting the safety of our grid to a utility industry that is ill-equipped to adequately and uniformly respond to threats and vulnerabilities that are of paramount importance to national security, then you can and must take action to mitigate these threats and vulnerabilities to the extent possible by executive order. I thank you for your dedication to this issue, and I look forward to continuing to work with you to ensure the reliability of our nation?s electricity grid. Sincerely, Edward]. MarkgI a Member of Congress NERC ISSUES EEI Fall Board and Chief Executives Meeting, September 2012 NERC is expected to publish Version 5 of the Critical Infrastructure Protection (CIP) Standards for ballot and comment in early September. EEI believes that it is critical for our industry to reach consensus and complete proposed modifications to CIP 5 consistent with the FERC deadline. A concerted effort on the part of EEI and member company CEOs will be necessary to reach a successful ballot on CIP Version 5. EEI Board Lead: Kevin Burke, Chairman, President & CEO, Consolidated Edison Inc. NERC CIP Standards  Background and Status, June 2012    In May 2006, the North American Electric Reliability Corporation (NERC) Board of Trustees approved the  first set of mandatory Critical Infrastructure Protection (CIP) standards.  These standards require asset  owners and operators to implement a set of security protections and controls over certain elements of  the bulk electric system.  In January 2008, the Federal Energy Regulatory Commission (FERC) approved the CIP standards, which  brought mandatory and enforceable regulations that include physical security, cyber security, training  and personnel controls.  FERC Order No. 706 also directed over 100 changes to the NERC CIP standards.  Over the past four years, these multiple FERC directives for modifications to the CIP standards have  created a series of major changes to the standard language.  These changes have caused significant  increased investments by member companies to achieve compliance.  In response to criticism by FERC and Congress that the industry was failing to identify a sufficient  number of “Critical Assets” that would be subject to mandatory and enforceable controls, the CIP  Standards Drafting Team produced Version 4 of the CIP Standards which uses a “Bright Line” criterion,  rather than risk‐based self selection, for determining which assets in the bulk electric system (BES)  should be required to have CIP security protections and controls.    In a recent significant development, on April 19 of this year, FERC issued Order No. 761 which approved  Version 4 and the “Bright Line” criterion.  However, Order No. 761 also established a deadline of March  31, 2013, for NERC to address the 50+ remaining FERC CIP directives.   Order No. 761 also signaled  FERC’s expectation that Version 5 cover all BES assets to some degree, rather than just “Critical Assets,”  and include additional electronic components that have not been subject to regulation up to this point.  To resolve outstanding Order No. 706 and Order No. 761 directives, a comprehensive re‐write of the CIP  standards is necessary and is expected to increase scope, compliance requirements, and cost to EEI  member companies.  EEI members have identified the following key challenges for CIP Version 5:  • • • All cyber assets, including those of low impact are in scope  Concern regarding “perfect compliance” (zero defect) risk  Complexity of applying the requirements  Although distribution assets are not in scope for either FERC/NERC regulation or CIP Version 5, the  number of additional bulk electric system assets and components that will be covered is anticipated to  create additional significant costs and compliance risk for member companies.  We believe that it is very important for the industry to reach consensus and complete modifications to  CIP Version 5 consistent with the FERC deadline.  A successful ballot that allows NERC to file by March 31, 2013, will:  • • Reflect the ability of industry to respond to government requests for action on CIP issues,  Re‐enforce the ability to sustain stakeholder‐driven standards development.  An unsuccessful ballot and continued disagreement on Version 5 changes could:  • • • Result in new or revised cyber standards filed by NERC, that may not advance reliability and may  increase costs even more,  Result in major changes in how reliability standards are developed in the future with less  stakeholder input,  Endanger the entire Electric Reliability Organization model.  The CIP Standards Drafting Team has been working on Version 5 of the CIP standards since early 2011,  and has issued two drafts of a proposed Version 5 for industry ballot and comment.  From now through  August, the CIP Standards Drafting Team is developing Draft 3 of CIP Version 5.    EEI member companies are well represented on the CIP Standards Drafting Team, with 8 of 16 voting  seats.   However, a larger ballot pool will vote on the proposed standard, with only 34% (166 of 486)  consisting of EEI member companies/affiliates.   Timeline:  • • • • September 2012 – NERC posts the next draft of CIP Version 5 for a third ballot to take place in  October 2012  October 2012 – Completion of third ballot by industry on CIP Version 5  February 2013 – NERC Board of Trustee reviews, votes on CIP Version 5  March 2013 – FERC deadline to file CIP Version 5  Action Items:  EEI   • • • • Coordinate with EEI company Standards Drafting Team representatives to improve the language  of CIP Version 5  Contact CEOs with staff on Standards Drafting Team, as appropriate  Coordinate outreach to other trade associations  Coordinate outreach to non‐EEI entities in support of October ballot  CEOs   • • • Meet with staff to ensure that they engage now on CIP Version 5  Reach out to non‐EEI entities (cooperatives and public power) to achieve support for October  2012 ballot  Drive to a positive outcome for the October CIP standards ballot    EEI Member companies with representatives on the CIP Standards Drafting Team: Consolidated Edison,  Southern, Duke, American Electric Power, Exelon, Constellation, So. Cal Ed, Arizona Public Service    2    NERC – Registered Ballot Body of Shareholder-Owned Electric Companies September 5, 2012 AES Corp. Leo Bernier Alabama Power Company Robert S. Moore Alliant Energy Kenneth Goldsmith Ameren Services Kirit Shah Mark Peters Jennifer Richardson American Electric Power Paul B. Johnson Michael E Deloach Brock Ondayko American Transmission Company, LLC Andrew Z. Pusztai Arizona Public Service Co. Robert Smith Steven Norris Edward Cambridge Randy A. Young Atlantic City Electric Nicole Buckman Avista Corp. Scott J Kinney Robert Lafferty Edward F. Groce Baltimore Gas & Electric Company Gregory S Miller BC Hydro and Power Authority Patricia Robertson Pat G. Harrington Clement Ma Black Hills Corp Eric Egge Andy Butcher George Tatar Andrew Heinle CenterPoint Energy Houston Electric, LLC John Brockhan 1 NERC – Registered Ballot Body of Shareholder-Owned Electric Companies September 5, 2012 Central Hudson Gas & Electric Corp. Frank Pace Thomas Duffy Central Maine Power Company Joseph Turano Jr. Cleco Power LLC Danny McDaniel Michelle Corely Stephanie Huffman Robert Hirchak Commonwealth Edison Bruce Krawczyk Consolidated Edison Co. of New York Christopher L de Graffenried Peter T. Yost Wilket (Jack) Ng Nickesha P. Carrol Constellation Energy CJ Ingersoll Donald Schopp Consumers Energy David F. Ronk David C. Greyerbiehl Consumers Power Inc. Stuart Sloan Richard Blumenstock Roman Gillen Dayton Power & Light Co. Hertzel Shamash Jeffrey Fuller Jason Procuniar Delmarva Power and Light Michael R. Mayer Detroit Edison Company Kent Kujala Daniel Herring Christy Wicke 2 NERC – Registered Ballot Body of Shareholder-Owned Electric Companies September 5, 2012 Dominion Virginia Power Michael S Crowley Connie Lowe Mike Garton Lewis S. Slade Duke Energy Carolina Douglas E. Hils Henry Ernst Jr. Dale Q. Goodwine Greg Cecil Mike Pullen Electric Energy, Inc. El Paso Electric Company Dennis Malone Tracy Van Slyke David Hawkins Tony Soto Empire District Electric Co. Ralph F Meyer Kalem Long Entergy Oliver A Burke Joel T. Plessinger Terry F. Benoit Exelon Pulin Shah FirstEnergy Corp. William J Smith Stephan Kern Kevin Querry Florida Power & Light Co. Mike O'Neil Lee Schuster Silvia P. Mitchell GenOn Energy James W. Mason Georgia Power Danny Lindsey Gulf Power Paul Caldwell Hydro One Networks, Inc. Ajay Garg David Kiguel 3 NERC – Registered Ballot Body of Shareholder-Owned Electric Companies September 5, 2012 Hydro-Quebec TransEnergie Bernard Pelletier Iberdrola USA Kellie Schreiner Idaho Power Company Molly Devine Shaun Jensen Indianapolis Power & Light Co. Michael Holtsclaw Integrys Energy Group Christopher Plante Kansas City Power & Light Co. Michael Gammon Charles Locke Brett Holland Jessica L. Klinghoffer LG&E Energy Transmission Services Bradley C. Young Charles A. Freibert Madison Gas & Electric Darl Shimko Joseph DePoorter Steven Schultz Jeffrey Keebler MidAmerican Energy Co. Terry Harbour Thomas C. Mielnik Neil D. Hammer Dennis Kimm Minnesota Power, Inc. Randi K. Nyholm William Boutwell Mississippi Power Jeff Franklin Montana-Dakota Utilities Co. Henry Ford National Grid USA Michael Jones New York State Electric & Gas Corp. Raymond Kinney 4 NERC – Registered Ballot Body of Shareholder-Owned Electric Companies September 5, 2012 NextEra Energy Allan D. Schriver Niagara Mohawk (National Grid) Michael Schiavone Northeast Utilities David Boguslawski Northern Indiana Public Service Co. William SeDoris William O. Thompson Joseph O’Brien NorthWestern Energy John Canavan NStar Gas and Electric John Robertson Ohio Edison Douglas Hohlbaugh Ohio Valley Electric Corp. Robert Mattey Oklahoma Gas and Electric Co. Marvin E VanBebber Gary Clear Kim Morphis Oncor Electric Delivery Jen Fiegel Orange and Rockland Utilities, Inc. Edward Bedder David Burke Otter Tail Power Company Daryl Hanson Stacie Hebert Pacific Gas and Electric Company Bangalore Vijayraghavan Richard Pidlla John H. Hagen PacifiCorp Ryan Millard Dan Zollner Sandra L. Shaffer Kelly Cumiskey PECO Energy Ronald Schloendorn 5 NERC – Registered Ballot Body of Shareholder-Owned Electric Companies September 5, 2012 Pepco Holdings, Inc. Mark R. Jones James Newton PNM Resources Michael Mertz Potomac Electric Power Robert Reuter David Thorne Portland General Electric Co. John T Walker Thomas G. Ward Matt E. Jasterm John Jamieson PPL Electric Utilities Corp. Brenda L Truhe Annette M. Bannon Elizabeth Davis Progress Energy John T. Sturgeon Progress Energy Carolinas Brett A. Koelsch Sam Waters Wayne Lewis Public Service Electric and Gas Co. Kenneth D. Brown Jeffrey Mueller Tim Kucey Peter Dolan Puget Sound Energy, Inc. Denise M Lietz Aaron Apperson Tom Flynn Rochester Gas and Electric Corp. John C. Allen San Diego Gas & Electric Will Speer Scott Peterson Daniel Baerman SCE&G Henry Delk, Jr. Hubert C. Young 6 NERC – Registered Ballot Body of Shareholder-Owned Electric Companies September 5, 2012 Sierra Pacific Power Co. Rich Salgo South Carolina Electric & Gas Co. Tom Hanzlik Edward Magic Matt Bullard Southern California Edison Company Steven Mavis David D. Coher Lujuanna Medina Southern Company Services, Inc. Robert A. Schaffeld John Ciza Southern Indiana Gas & Electric Fred Frederick Brad Lisembee Tampa Electric Co. Beth Young Ronald L. Donahey R. James Rocha Benjamin F. Smith II Tucson Electric Power Co. John Tolo Michael Bowling United Illuminating Co. Jonathan Appelbaum Unitil Richard Francazio Vermont Electric Power Company, Inc. Kim Moulton Westar Energy Allen Klassen Bo Jones Bryan Taggart Grant L. Wilkerson Gregory J. LeGrave Paul Spicer Wisconsin Public Service Corp. Xcel Energy, Inc. Gregory L Pieper Michael Ibold Liam Noailles David Lemmons 7 FERC ISSUES EEI Fall Board and Chief Executives Meeting, September 2012 Transmission ROE and Incentives Policy Patricia K. Vincent-Collawn, Chairman, President and CEO of PNM Resources, and cochair of the CEO Policy Committee - Energy Delivery, will provide an update and lead a discussion on the need for adequate transmission ROE and continued application of FERC’s transmission rate incentives policy. At prior CEO meetings, EEI has garnered support for, and implemented a strong advocacy message on the need for (i) stable and adequate return on equity for transmission investment given its many challenges and benefits, and (ii) the value of FERC’s incentives rate policy for qualifying projects. Some CEOs have met with FERC Commissioners to advocate for adequate transmission ROEs and retention of FERC’s incentives policy. Transmission ROE FERC now has five pending case-specific complaints requesting lower ROEs than currently effective, including a complaint joined in by a number of states requesting a lower ROE for ISO-New England. Three were filed after the June 2012 CEO meetings. These complaints request that FERC reduce base transmission ROE by 100-200 basis points or more. Significance for Members Adequate ROEs, base and any incentive adder that may be requested under FERC’s incentive policy, are facing broad challenges. If FERC grants these requests, members will be further challenged to secure financing at reasonable rates and maintain or improve credit ratings, and provide adequate returns to stockholders. Trends for increasing complaints requesting significant reductions in base ROEs could hamper access to capital to make needed transmission investments, reduce regulatory certainty and investor confidence in stable returns, and threaten corporate credit ratings. Incentives Policy EEI has submitted comments to FERC in its Notice of Inquiry proceeding on incentives emphasizing the value of transmission, refuting misstatements and unsupported claims that incentives are excessive and provide no benefits, and defending adequate returns. In addition, EEI has developed several advocacy materials, including talking points, leavebehinds and fact sheets, to support member outreach to FERC as well as Capitol Hill. These materials are provided herein. Title EEI Fall Board and Chief Executives Meeting, September 2012 EEI’s advocacy is focused on retaining the incentives that the industry has under existing policy, while countering pushback from states and consumer groups that incentives are excessive. Pushback continues to be especially strong from states, as evidenced most recently at the July 2012 NARUC summer meetings during the Transmission Unplugged panel, summarized in the Transmission Hub article included herein. Significance for Members Increased difficulty in securing the appropriate incentives, as provided by FERC policy implementing section 219 of the Federal Power Act, for the riskiest transmission projects These projects will address reliability, economic and public policy needs. Action Item Continue outreach to FERC Commissioners and staff on (1) the need for adequate returns to finance needed transmission, projected to range from $12-15 billion per year through 2015, as indicated in the attached EEI’s Actual and Planned Transmission Investment 2006-2015 and (2) retention of FERC’s transmission rate incentives policy with some minor changes as noted in the EEI Reply Comments provided herein. EEI Board Lead Patricia K. Vincent-Collawn, Chairman, President and CEO of PNM Resources, and co-chair of the CEO Policy Committee - Energy Delivery. 2 NARUC: Common challenges to transmission development identified Session identifies common issues but not solutions 07/24/2012 By Carl Dombek More than a dozen delegates representing transmission developers, utilities, ISOs and RTOs, renewable energy developers, and nongovernmental organizations discussed the state of transmission in a discussion billed as Transmission UNPLUGGED! at the National Association of Regulatory Utility Commissioners (NARUC) summer committee meetings in Portland, Ore. The idea, according to the chair of the July 23 panel, was to create an atmosphere that would encourage a free-wheeling discussion of the issues each participant found important with regard to transmission planning and development. No prepared slide presentations were allowed, and each panelist was allotted only a few minutes for brief opening remarks before tackling questions posed by commissioners and audience members. As intended, the 2.5 hour discussion was robust but, perhaps as a result of the unstructured approach or perhaps as a reflection of the diversity of interests within the industry, each participant had their own take on the issues that emerged. One point of general agreement was that the transmission planning process needs to be improved. The process should be a “multi-driver planning process” where all the benefits are considered: reliability, economic benefits, and the facilitating of public policy issues including bringing renewable energy to market, according to Marc Lewis, vice president of external relations for Indiana Michigan Power. Acknowledging that there are “significant and well-documented impediments” to getting ISO and RTO planning processes to that level, Lewis said, “We need to get beyond ‘just-in-time, and justenough’ planning.” Others called for more regional planning of the sort that Order 1000 “stops just short of mandating,” as one participant put it. “States can’t do it alone,” Jimmy Field, commissioner with the Louisiana Public Service Commission, said. “We have to [plan] regionally for national security and our national interest.” Others advocated expanding planning beyond regional planning. “Interconnection-wide planning is a good way to examine different public policy requirements,” Flora Flygt, strategic planning and policy advisor for American Transmission Company (ATC), said. While most panelists agreed with the idea of regional planning in principle, Illinois Commerce Commission member ErinO’Connell-Diaz asked, “How do you get around states’ rights? Without a federal energy policy that would mandate that, there’s a question of how that would ever work.” Rate incentives a hot button issue Transmission incentives were another area of discussion, and an area that developed something close to consensus. While most panelists advocating a reduction in the granting of incentives, not everyone agreed. “We need incentive rates,” Flygt said. “Building transmission is risky.” Others said FERC needs to be more judicious in awarding incentive rates, and “distinguish between incentives that reduce the utility’s risk and those that increase the utility’s returns. They are quite different incentives,” John Anderson, president and CEO of the Electricity Consumers Resource Council (ELCON) said, noting that regulators should also reduce the return on equity (ROE). “It absolutely doesn’t make any sense at all to reduce the risk and then leave the ROE the way that it is.” Whiles some participants called for moderation, others said the time for incentives has passed. “We’re not saying incentives are never needed, but we would like to make them not the ‘new normal,’ as they have become,” Sue Kelly, vice president of policy analysis and general counsel of the American Public Power Association (APPA), said. “I’m inclined to believe we don’t need incentive rates,” Field said. “Utilities don’t have a lot of risk anymore.” One participant cited a study that said incentives were less pervasive than many believe. “EEI looked at transmission incentives [and found that] only 5% of the transmission built in 2009-2010 had incentives,” Jim Fama, vice president of energy delivery with the Edison Electric Institute (EEI), said. Cost allocation Another issue everyone agreed needs to be improved is cost allocation. How to improve the process was the tougher nut to crack. Cost allocation must match those who benefit with those who pay, Clair Moeller, vice president of transmission asset management with the Midwest ISO (MISO), said. “We don’t see there being one silver bullet cost allocation for the nation,” Kelly said. “Different regions may need to settle on different solutions, and those solutions may well change over time. Everybody has to learn to give a little bit to get a little bit.” For some, the breakdown is simple. “We are strong advocates of the cost-causation principle,” Anderson said. “Those who cause the costs should pay for the costs.” Legislation intended to aid the process Toward the end of the session, FERC commissioner John Norris addressed several of the identified areas. “Incentive policy is a Congressional directive … all under the premise that we need to have a more robust transmission grid to support a wholesale competitive marketplace for dispatching, and access to, least-cost generation,” Norris said. He also addressed planning, siting, and cost allocation in light of the court decision denying FERC backstop siting authority granted in the Energy Policy Act of 2005 (EPAct05).“Without some sort of backstop siting authority, that seems to me to be the biggest inhibitor to getting transmission built,” Norris said. “Incentives have helped, but if we really want to get transmission built that goes through the regional planning process, the siting is a huge obstacle once we overcome the obstacle of deciding on a proper cost allocation.” Indiana-Michigan Power is a unit of American Electric Power (NYSE:AEP). About the Author Carl Dombek Carl Dombek, senior editor for TransmissionHub, is an award-winning journalist with nearly two decades of experience as a broadcast journalist on radio and TV, and as a writer for newspapers, magazines, and the Web. Prior to joining TransmissionHub, Carl spent five years in the U.S. power industry, including positions at the North American Electric Reliability Corporation and the Midwest ISO. Contact Carl Dombek at cdombek@energycentral.com. 701 Avenue. NW. Washington, Ill). 20004-2596 Telephone 202-508-552? dowens@eei.org DAVID K. OWENS Executive Vice Presidenl Business Operations EDISON ELECTRIC INSTITUTE May 21, 2012 Honorable. Jon Wellinghoff, Chairman Federal Energy Regulatory Commission 888 First St. NE Washington, DC 20426 Subject: Notice of Inquiry. Docket No. RM11-26-000 Dear Chairman Wellinghoff, Attached please ?nd a copy of the reply comments filed last Friday, May 18, by Edison Electric Institute (EEI) in Promoting Transmission Investment through Pricing Reform, Docket No. RM11-26-000, originally promulgated in Order No. 679 and now on review pursuant to the Commission?s Notice of Inquiry issued in May 2011. EEI seeks careful consideration of its reply comments to balance the record in this proceeding in response to recent comments ?led with the Commission. reiterates its support, on behalf of its members, for the Commission?s incentives policy. As Congress recognized in adding section 219 to the Federal Power Act, signi?cant amounts of transmission are needed to reduce congestion, integrate renewable technologies, and ensure reliability. EEI strongly believes that major changes to the Commission's incentives policy are unnecessary and counterproductive because: adequate returns for transmission investment continue to be needed to attract sufficient transmission investment and do not result in unjust rates; (ii) implementation of the policy has not burdened consumers; existing planning processes protect against unnecessary transmission investment; and (iv) transmission developers continue to face significant risks completing projects which necessitate offsetting incentive measures for the riskier projects. I look forward to further dialogue on the Commission?s incentives policy initiative. Respectfully, drow? 0W David K. Owens. Executive Vice President Edison Electric Institute Actual and Planned Transmission Investment By Shareholder-Owned Utilities (2006-2015) ($ Millions [Real $2011]) 16000 15,152 14000 13,973 13,075 12000 10000 8000 12,424 11,672 10,314 8,627 8,876 10,680 Note: The Handy-Whitman Index of Public Utility Construction Costs used to adjust actual investment for inflation from year to year. Forecasted investment data are adjusted for inflation using the GDP Deflator. 9,460 6000 *Planned total industry expenditures are preliminary and estimated from 85% response rate to EEI’s Electric Transmission Capital Budget & Forecast Survey. Actual expenditures are from EEI’s Annual Property & Plant Capital Investment Survey and FERC Form 1 reports. 4000 2000 Source: Edison Electric Institute, Business Information Group. 0 2006 2007 2008 Actual 2009 2010 2011 2012 2013 2014 2015 Planned* Note: The Handy-Whitman Index of Public Utility Construction Costs used to adjust actual investment for inflation from year to year . Forecasted investment data are adjusted for inflation using the GDP Deflator. Updated as of July 2012. © 2012 by the Edison Electric Institute. All rights reserved. FERC ISSUES - BASE ROE COMPLAINTS Docket No. Utility(ies) Complainant(s) Current ROE Requested ROE Status 11.14% 9.2% Settlement negotiations terminated Aug. 2012; hearing scheduled for May 2013 10.8% 9.02% initial order pending before FERC EL11-66 Bangor Hydro-Electric Central Maine Power National Grid NextEra NSTAR NU Utilities CL&P WMECO Public Service Co. of NH United Illuminating Unitil Vermont Transco Massachusetts Attorney General, et al. EL12-39 Florida Power Corporation (d/b/a Progress Energy Florida) Seminole Electric Cooperative Florida Municipal Power Agency EL12-59 Southwestern Public Service Co. Golden Spread Electric Cooperative 11.27% 9.65% initial order pending before FERC EL12-77 Public Service Co. of Colorado Grand Valley Rural Power Lines Yampa Valley Electric Assoc. Intermountain Rural Electric Assoc. Tri-State Generation & Trans. Assoc. 10.25% 9.15% initial order pending before FERC EL12-84 Maine Public Service Co. MPS Customer Group 10.5% 8.83% initial order pending before FERC ENVIRONMENT EEI Fall Board and Chief Executives Meeting, September 2012 The U.S. electric utility industry is faced with a number of critical environmental policy and regulatory issues that are impacting company strategic planning and decisionmaking. In combination with record low natural gas prices, slow economic growth, increased use of renewable energy and an aging fleet, these issues are spurring major investment in electric power generation and transmission. For example, almost 60 gigaWatts of publicly announced coal plant retirements could take place between 2010 and 2022. Consistent with this trend, in April 2012 coal and natural gas generation reached parity for the first time. The September CEO meeting will feature updates and discussion on several key environmental issues, including greenhouse gas new source performance standards, the § 316(b) cooling water intake structures rule, the coal combustion residuals rule and corresponding Congressional activity, the status of the Cross-State Air Pollution Rule in the wake of the D.C. Circuit’s decision, EPA’s state-by-state regional haze program, and implementation of the final mercury rule. This segment of the Board meeting will be facilitated by the co-Chairs of the Policy Committee on Environment, DTE Energy’s Gerry Anderson and Public Service Enterprise Group, Inc.’s Dr. Ralph Izzo. § 316(b) Cooling Water Intake Structures Rule Two significant developments have occurred recently: (1) EPA renegotiated the settlement deadline for issuing a final rule to June 27, 2013; and (2) in July, EEI filed comments in response to two supplemental Notices of Data Availability (NODA) pertaining to EPA’s pending rulemaking for cooling water intake structures (CWIS) at existing facilities under section 316(b) of the Clean Water Act. EEI, its member companies and allied groups also were successful in obtaining helpful House and Senate letters. Under the proposed rule, many facilities may be compelled to retrofit cooling towers at a nationwide cost estimated to be as high as $100 billion, and many facilities will be required to retrofit technology whose costs will far exceed the benefits, potentially making those units uneconomic. The proposed impingement standards are not achievable at all existing facilities, and there is no valid environmental or biological justification for precluding site-specific flexibility for impingement as EPA has proposed for entrainment. The impingement mortality (IM) NODA proposed a number of changes in the rule to address these concerns, such as allowing more flexibility and the inclusion of pre-approved technologies. Industry supports many of these proposed changes, as well as the proposed rule’s site-specific approach to entrainment reduction. Environment EEI Fall Board and Chief Executives Meeting, September 2012 However, EEI is very concerned with the second NODA, which proposes the use of a public opinion survey as a surrogate for well-established biological and economic analyses to estimate expected regulatory benefits. Industry does not believe surveys of this type are an appropriate tool for use in a national or regional context and should not be used by EPA to justify its final § 316(b) rule. The recently negotiated delay in the deadline for finalizing the rule is also of concern, as it may be used by EPA to develop further justification via the use of such surveys for a more onerous final rule that may not incorporate some of the positive changes suggested in the IM NODA. CEOs will be asked to continue their advocacy efforts on this important issue. As needed, EEI will set up high-level agency meetings enabling company executives to communicate industry concerns to policymakers. In addition, as more intelligence becomes available relative to EPA’s intentions, periodic CEO conference calls will be held to discuss further recommended actions. For more information see the Cooling Water Intake Structure Rule strategic environmental issue summary. Greenhouse Gas New Source Performance Standards EEI submitted comments June 25 on EPA’s proposed greenhouse gas new source performance standards (NSPS) for new fossil fuel-based units. Proposed regulations for modified, reconstructed and existing plants are expected after November 2012. Importantly, while not directly related to the NSPS rulemaking, EPA’s authority to regulate greenhouse gases under the CAA was given a boost by the D.C. Circuit Court of Appeals, which unanimously upheld EPA’s endangerment finding and tailpipe, timing and tailoring rules. Conversely, Congress has considered but not enacted numerous proposals that would affect EPA’s ability to address GHGs under the CAA. One major concern with the NSPS is that it effectively precludes the building of new coal-based power plants, since only a new coal plant using carbon capture and storage technology—which currently is not commercially available—could meet such a standard. Another concern is that, in many circumstances, the NSPS for new natural gas combined-cycle (NGCC) units cannot be achieved under normal, realworld operating conditions because EPA did not take into consideration a number of critical factors (e.g., startups, shutdowns, normal equipment wear and tear, etc.). EEI’s comments urge EPA to set a separate standard for new coal-based power plants and to raise the emissions standard for new NGCC units. EPA also needs to clarify coal-based units that are modified to comply with new CAA and other environmental regulations will not be subject to the proposed GHG NSPS, with which they could not comply. EEI has prepared new outreach tools on these issues. CEO actions likely will include additional meetings with EPA and other Administration officials, especially as EPA increases its focus on how best to regulate existing, modified and reconstructed sources. For more information see the GHG CAA strategic environmental issue summary. 2 Environment EEI Fall Board and Chief Executives Meeting, September 2012 Cross State Air Pollution Rule On August 21, the D.C. Circuit Court of Appeals issued a two-to-one decision vacating CSAPR. Finalized in August 2011, CSAPR was designed to replace the Clean Air Interstate Rule (CAIR), EPA’s original attempt to address interstate transport of SO2 and NOx that was remanded to EPA by the same court in 2008. The court in this most recent ruling directs EPA to leave CAIR in place while moving “expeditiously” to finalize a replacement interstate transport rule. It likely will be several years before a replacement rule is effective. The decision has two main holdings: (1) that EPA exceeded its authority under the Clean Air Act (CAA) by requiring states to reduce emissions beyond the level of their significant contribution to other states’ nonattainment; and (2) that EPA exceeded its CAA authority by imposing FIPs (federal implementation plans) on states without giving them an opportunity to propose their own SIPs (state implementation plans.). EPA has 45 days to file an appeal. While CSAPR is vacated, health and environmental protections remain in place under CAIR, the Mercury and Air Toxics Standards (MATS), regional haze rules, and National Ambient Air Quality Standards. In June, EPA issued supplemental rulemakings associated with the final CSAPR to correct data errors and allow CSAPR compliance to satisfy the obligation to meet the Best Available Retrofit Technology (BART) requirements for regional haze. In August, new litigation challenging both of these actions was initiated in the Fifth and D.C. Circuits by state, industry and environmental groups. The Court’s vacatur of the underlying CSAPR program likely moots these legal challenges. EPA probably will reinstate the rule that allowed compliance with CAIR to meet BART requirements for regional haze for eastern states. The most likely practical effect of this decision is that the MATS rule will continue to be the driving force for compliance decisions in the near term, though it is possible that some companies eventually may have to install additional controls to satisfy a replacement interstate transport rule. It is too soon to know the interplay between expected MATS reductions and potential future reductions that might be required by a replacement rule. A replacement rule should take into account the emission reductions that will be achieved by MATS compliance. It could take three or more years before companies would have to comply with a replacement rule, given the complexity of the necessary modeling needed to allocate allowances to states based on their level of significant contribution and the need to give states an opportunity to propose compliant SIPs. EEI will prepare a detailed analysis of the decisions for members and monitor whether EPA seeks an appeal or begins to work on a replacement for the vacated CSAPR. For more information see the CSAPR strategic environmental issue summary. Particulate Matter National Ambient Air Quality Standards EPA has proposed to tighten the health-based annual fine particulate matter (PM2.5) National Ambient Air Quality Standards (NAAQS), to retain the 24-hour health-based standard and to establish a secondary (welfare-based) standard to address urban visibility concerns. EEI will submit comments by the August 31 deadline. EPA has entered into a consent decree requiring it to finalize the rule by December 14 (i.e., only 105 days after the comment deadline), an unprecedented short review period in light of the expected heavy volume of comments addressing new concepts such as the proposed secondary standard and roadside monitoring; the new roadside monitoring requirement in approximately 3 Environment EEI Fall Board and Chief Executives Meeting, September 2012 50 large cities could significantly increase the stringency of the annual standard. This truncated timeline contradicts EPA’s prior claim that the PM NAAQS could not be finalized before August 15, 2013. Tightening the PM2.5 and other NAAQS will create many new non-attainment areas and lead to new state planning for additional control measures, likely requiring new controls for power generators beyond those in the MATS and CSAPR regulations. Other impacts of the near simultaneous implementation of multiple NAAQS standards include a possible increased focus on NAAQS in the west and possible new EPA rules to address interstate transport. New plants in non-attainment areas face the ultimate challenge of meeting “lowest achievable emission rate” requirements and obtaining emission offsets. Offsets often are in scarce supply and very expensive. New power plants and industry sources may avoid locating in areas that fail NAAQS. CEOs will discuss potential outreach to EPA and other Administration officials. For more information see the NAAQS strategic environmental issue summary. Regional Haze EPA is reviewing and will take action on virtually all state regional haze plans by early 2013, including unit-specific and expensive BART determinations. A number of recent EPA decisions have been controversial and two states already have sued the agency. Importantly, in other cases (e.g., Montana) EPA has partially backed away from its initial efforts to impose very strict Federal Implementation Plans (FIPs) in lieu of state-backed proposals. The vacatur of the CSAPR negates the June 2012 EPA rule that CSAPR compliance can satisfy BART requirements; EPA will need to reinstate the CAIR=BART finding or the CSAPR ruling will undermine many Eastern state BART decisions. Tools being used or supported by EPA to model air quality and to estimate costs of environmental controls are outdated and produce results very different from current state-of-the-art tools (e.g., updated versions of the CALPUFF air quality model). Using these substandard tools and approaches, EPA has rejected, or signaled its intent to disapprove, several state implementation plans (SIPs) and, alternatively, implement controversial FIPs. A CEO work group is continuing to direct industry efforts to constructively affect this policy issue on both a programmatic and state-by-state basis, including meetings with EPA and other Administration officials, outreach to Congressional and state officials, and development of new advocacy tools. A key message, reflected in legislative language adopted by the House Appropriations Committee in June, is that EPA should work with the industry and other stakeholders to quickly update its regional haze tools and should not make important regulatory decisions based on outdated tools. CEOs will discuss next steps, particularly regarding specific states where there remain differences of opinion with EPA on the role of state versus federal decision-making as well as assumptions about costs of controls and projected visibility benefits. For more information see the Regional Haze strategic environmental issue summary. Mercury and Air Toxics Standards Rule Implementation of the MATS rule continues notwithstanding numerous legal challenges and increased Congressional scrutiny. The rule will require most coal plants to upgrade existing controls and/or install 4 Environment EEI Fall Board and Chief Executives Meeting, September 2012 additional controls by April 16, 2015, with one key outcome of this process being that a significant number of coal-based plants necessarily will be retired or re-powered, most likely with natural gas. While the final rule contained some important improvements over the initial proposal, some companies remain concerned about the compliance timeline and availability of necessary extensions. An additional (fourth) year can be granted relatively liberally by states, and many states and RTOs/ISOs have asked electric utilities to start the application process for plants that will need a fourth year. An additional (fifth) year can be granted by EPA via an administrative order or consent decree for cases with a “specific and documented reliability concern.” It is unclear how this enforcement-based process would work in practice. To date, no utilities have applied to EPA for compliance time extensions beyond the four year window. In July, EPA agreed to reconsider certain new source standards issues and complete a rulemaking by March 2013, and to grant a partial stay of the effectiveness of the rule’s new source standards until November 2, 2012. CEOs will discuss ongoing implementation efforts, particularly any specific instances involving applications for more than four years or where there have been problems in obtaining a fourth year. For more information see the Utility MACT Rule summary. Coal Combustion Product Regulation EPA is considering two primary regulatory options for coal combustion products (CCPs) disposed of in landfills or surface impoundments: (1) regulation as hazardous wastes under Subtitle C of the Resource Conservation and Recovery Act (RCRA); or (2) regulation as non-hazardous wastes under Subtitle D of RCRA. Under both options, proposed regulatory requirements would lead to the closure of existing surface impoundments, although the agency’s so-called “D Prime” Option would allow the use of existing surface impoundments so long as environmental and safety standards are met. Under both options, CCPs that are beneficially used would be excluded from regulation; however, the stigma associated with hazardous waste regulation would have a devastating impact on continued beneficial uses. Federal regulations will have an impact on current CCP disposal practices and result in significant compliance costs, may lead to the closure of existing disposal facilities, and threaten continued CCP beneficial use. EPA has announced a final rule could be issued no earlier than late 2012. Separate groups of environmental organizations and ash marketers have filed lawsuits seeking to compel EPA to expeditiously complete the current rulemaking, albeit with different strategic objectives. The former want EPA to finalize a Subtitle C-based rule, while the latter are concerned with the ongoing erosion of market share. USWAG has filed a petition to intervene in the lawsuit. The case will be briefed by late 2012. In October 2011, the House of Representatives passed H.R. 2273, the Coal Combustion Residuals and Management Act, legislation that would establish a state-implemented, non-hazardous waste regulatory program effectively prohibiting hazardous waste regulations. In April 2012, the House voted to include H.R. 2273 in the Surface Transportation Extension Act of 2012. During the House-Senate conference on the transportation bill, the coal ash language was revised to attract bipartisan support; ultimately, the compromise coal ash language was not included in the transportation bill conference agreement. On August 2, 2012, Senators Conrad (D-ND) and Hoeven (R-ND), along with 11 Democrat and 11 Republican co-sponsors, introduced S. 3512; this bill is virtually identical to the bi-partisan CCR 5 Environment EEI Fall Board and Chief Executives Meeting, September 2012 legislative package that was considered by Congress for inclusion in the Transportation Bill. EEI and USWAG have prepared new outreach tools on S. 3512. CEOs will be asked to continue to advocate the non-hazardous waste regulation of CCPs under state, rather than federal regulatory control; to develop and strengthen third-party support for non-hazardous regulation of CCPs; and to coordinate with Members of Congress, federal agencies, state officials and other stakeholders in support of the current legislative effort. For more information see the CCP strategic environmental issue summary. Other Issues While there are other major environmental policy issues where there has been recent developments of importance to the industry, time limitations may preclude their discussion at the September meetings. These issues include transmission siting, Waters of the United States, EPA revisions to steam electric effluent limitation guidelines, Clean Water Act Total Maximum Daily Load (TMDL) program, EPA regulations on the use of polychlorinated biphenyls (PCBs), and House-passed legislation to resolve legal conflicts between DOE emergency reliability orders and environmental laws. 6 Environmental Regulatory Challenges: 2012 and Beyond Land & Natural Resources Waste & Chemical Management 316(b) Transmission Siting and Permitting Coal Ash (CAIR/CSAPR) NSPSExisting Sources Effluent Guidelines Limitations Avian Protection PCBs in Electrical Equipment Regional Haze/Visibility BACT Permitting Waters of the United States Endangered Species HazMat Transport Multiple NAAQS International Negotiations NPDES Pesticide Permits Vegetation Management Air Climate Utility MACT NSPS- New & Modified Sources Interstate Transport New Source Review (NSR) Water WaterbodySpecific Standards 8/09/12  Coal Fleet Announcements Following is a summary of announced retirements of coal plants under which approximately 57,000 MW of generation (or 16.8% of the 339 GW of total coal-fired generation in 2010) will be retired between 2010 and 2022.1 Some units will be replaced with natural gas generation.2 Company AEP3 AES Alliant Ameren4 APS Black Hills Consumers5 Dominion6 DTE7 Duke8 Dynegy Edison Int’l9 Empire District EFH10 Exelon First Energy11 GenOn12 Great Plains Madison G&E MidAmerican NiSource13 NRG NV Energy OGE PGE PPL SCANA Southern14 TransAlta15 TVA16 WE Energies Xcel Energy17 Others Total MW 5,526 625 1,112 1,277 633 44 971 2,515 272 7,836 489 1,239 88 1,187 895 3,797 3,493 170 178 189 629 1,075 342 171 601 908 770 9,954 1,460 4,775 112 1,431 2,354 57,114 State Various NY, OH IA, WI MO, IL AZ CO MI MA, IN, VA MI, CA various IL IL Year(s) Built 1944-1980 1948-1955 1921-1969 1953-1961 1963, 1964 1955, 1959 1952-1958 1952-1992 1952-1989 1940-1978 1953-1959 1955-1968 1950, 1954 TX 1974-1975 PA 1954, 1960 various 1944-1972 OH, PA, VA 1949-1970 MO 1958 WI 1938-1961 UT 1954, 1957 IN 1950-1970 DE, MA, NY 1950-1970 NV 1965, ’68, ‘76 OK 1956 OR 1980 KY 1953-1969 SC 1953, ’58, ‘62 Various 1949-1967 WA 1971 TN, AL, KY 1952-1965 MI 1964, 1966 CO, MN 1951-1968 various 1939-2004 Year(s) Will Retire 2011-2014 2011-2015 2010-2018 2011, 2022 2015 2014 2015 2013-2022 2010-2013 2011-2020 2011-2013 2010-2014 2018 2012 2011-2012 2010-2015 2012-2015 2016 2010-2012 2015 2010-2012 2010-2014 2016 2010 2020 2015 2012-2018 2011-2020 2019-2024 2012-2117 2010 2010-2022 2010-2022 Units Retiring/Notes 25 units in 7 states 6 units 19 units 7 units 3 units 2 units 7 units 17 units 5 units 50 units (FL, IN, NC, OH, SC) 4 units 5 units 2 units 2 units (Luminant) 3 units 24 units (MD, OH, PA, WV) 25 units 1 unit 5 units 2 units (PacifiCorp) 6 units 8 units 3 units 1 unit Will retire Boardman plant 20 years early 6 units (LG&E and KU) 6 units 4 units currently (AL, FL, GA, MS) 2 units (Centralia) 25 units 2 units 12 units                                                               Retirements are taking place for a variety of reasons, including plant age, fuel prices (i.e., low natural gas prices), decreased demand, consent decrees and the settlement of EPA complaints, the projected cost of complying with pending EPA regulations, etc. Because some plant closure details and/or plans for replacement generation have not been finalized, it is not possible to determine the exact number of closures, the mix and quantity of generation replacing the retiring coal units, or the exact amount of emissions reductions.  1 8/09/12                                                                                                                                                                                                   To the degree that retiring coal plants are replaced with natural gas generation, mercury and SO2 emissions will be virtually eliminated and CO2 emissions reduced by almost half at those units. 3 On 6/09/11, AEP announced that as part of its plan for complying with EPA regulations, it would retire 6,000 MW of coal-fired generation—some of which will be replaced with natural gas units—belonging to its following subsidiaries: Kentucky Power, Indiana Michigan Power, Southwestern Electric Power, Ohio Power, Columbus Southern and Appalachian Power. Some of the plant retirements are part of a settlement agreement with EPA. On 2/10/12, AEP announced that it would keep Big Sandy 2 (800 MW) operating. 4 Ameren, in Feb. 2011 IRP filing in MO, indicated it would likely close Meramec 1-4 due to the cost of meeting pending EPA regulations. 5 Consumers Energy indicated, in a Dec. 2 press release, that it did not anticipate operating the 7 units past Jan. 1, 2015, but that market conditions and the final form and timing of federal and state environmental regulations could lead it to adjustment of its plans.  6 Dominion is retiring 17 units due in part to cost of complying with the pending EPA regs (Salem Harbor, State Line, Chesapeake, Yorktown); 4 units are being retired due to low natural gas prices; 3 units (Altavista, Hopewell, and Southhampton) are being converted to biomass and 2 to natural gas (Bremo Bluff, Yorktown). Some of these closures were included in a September 1, 2011, IRP filing. 7 DTE Energy Services has agreed to covert 2 coal-fired facilities to biomass—the Port of Stockton Energy Facility and the Mount Poso Cogeneration Plant (co-owned with Red Hawk Energy) 8 Data includes retirements announced by then-Progress Energy, now a part of Duke. The Beckjord 6 unit, which is co-owned with AEP subsidiaries Columbus Southern and Dayton Power & Light, is included in the Duke total. As part of its overall coal-fleet transition strategy, Duke announced an agreement in 2008 to retire 800 MW of coal-fired power in exchange for building new 825 MW clean coal facility at Cliffside. It is not clear which plant retirements relate to this announcement, with the exception of Cliffside 1-4. Duke also agreed to make the new facility carbon neutral by 2018 by offsetting approximately 5½ million tons of CO2/year) through the following means: depending more on nuclear power, further reducing power generated by coal-burning units, and using energy efficiency programs, carbon free tariffs and other “mitigation projects.” The new unit will: remove 99% of SO2, 90% of NOx emissions and cut mercury emissions by 50%; be built to accommodate installation and operation of carbon control technologies; significantly minimize thermal impacts to the local river; and, generate wall board quality gypsum from the wet scrubber. As part of an overall coal-fleet transition strategy, the former Progress Energy announced an agreement in December 2009 to retire 30% of its NC fleet (11 plants or approximately 1,500 MW of total capacity), replace some with natural gas plants, build new 950-MW natural gas plant at H.F. Lee plant site and build additional new 600-MW natural gas plant at Sutton Plant to replace coal generation being retired in order to maintain reliability. Progress’ remaining NC plants are scrubbed (spent $2 billion installing state-of-the-art control on remaining coal generation). The retirement of 2 units in FL (Crystal River 1 & 2) depends on approval to move forward with a new nuclear plant. 9 Edison International is closing the units under 2 different agreements with IL, and has also agreed to install SO and NOx controls on all 2 Midwest Gen plants. 10 Energy Future Holdings Corp. subsidiary Luminant announced on September 12, 2011 that it would idle 2 units to comply with CSAPR. 11 On Feb. 8, 2012, FirstEnergy announced that it would retire 3 coal-fired plants in WV due to the cost of complying with the MATS regulation. On January 26, 2012, FirstEnergy announced that it would retire 6 coal-fired facilities, 2 of which—Armstrong and R. Paul Smith—had not previously been unannounced, due to the cost of complying with MATS. In August 2010, FE announced that it would retire all or part of 2 coal-fired peaking plants (Lake Shore and Ashtabula)—and reduce operations at 2 other plants (Bay Shore and Eastlake)—due to decreased demand, plant age, etc. All of these units will now be retired. FE is retiring 2 other units (R.E. Burger) under a consent decree with EPA. 12 On Feb. 29, 2012, GenOn announced that it would close 7 plants due to the costs of complying with MATS. 13 Retirement of Dean Mitchell units is part of a consent decree w/ EPA 14 Southern is retiring the plants due primarily to the cost of complying with pending EPA regs. Southern has announced plans to convert the Mitchell plant to biomass (currently on hold). On August 4, 2011, Southern filed comments that it expects to retire 4,000 MW of coalfired generation—and repower approximately 4,700 MW of coal and oil-fired generation to natural gas and other fuels—as a result of compliance with the pending EPA regs, but has not specified which plants would be affected. 15 Under agreement with state, TransAlta will install SNCRs on the units in 2013, invest $55 million on energy efficiency and clean energy technology development, and be allowed to sell power in-state from the plants under long-term contracts until they close. 16 As part of settlement agreement with EPA (04/14/2011), TVA agreed to retire or idle the following coal plants: Johnsonville 1-10, John Sevier 3-4 and Widows Creek 1-6. In addition, TVA has agreed to spend $3-$5 billion in additional pollution control equipment for its remaining coal plants and $350 million on air pollution reduction and energy efficiency projects, as well as pay a $10 million civil penalty. Separately, TVA announced on 8/24/10 it would retire Shawnee 10 and John Sevier 1 & 2. 17 In 2010, Xcel Energy announced a plan to reduce the NO emissions of its Colorado fleet, in response to state law that required the x company to meet anticipated federal clean air regulations. Xcel Energy will invest $1 billion to retire or switch to natural gas approximately 900 MW of coal-fired generation. In addition, the company will install modern emissions controls for 950 MW of coal-fired generation. In Minnesota, the company plans to retire 270 MW at Black Dog. To date, the company has reduced regulated emissions on average 40% from 2005 levels. 2 Generation Fuel Mix Electricity Net Generation 60% 50% Coal 40% 30% Natural Gas Nuclear 20% Coal Natural Gas Nuclear 10% Hydro + Other RE Other 0% J F MAM J J A S OND J F MAM J J A S OND J F MAM J J A S OND J F MAM 2009 2010 2011 2012 (Source: Energy Information Administration, Monthly Energy Review July 2012) Hydro + Other RE Other ELECTRIC TRANSPORTATION EEI Fall Board and Chief Executives Meeting, September 2012 The Edison Electric Institute (EEI) has a long-standing commitment to supporting the electrification of the transportation sector. EEI and its member companies continue to promote the expansion of the alternative fuel transportation market through a comprehensive campaign focused on reinforcing utility operational benefits, advocating for positive federal and state public policies, and advancing new business opportunities. As awareness and adoption of plug-in electric vehicles (PEVs) grow, and the potential of fleet and off-road applications are fully realized, there are even greater opportunities to promote the value of electricity as a transportation fuel and the role of electric utilities as the fuel provider for these technologies. EEI Board Leads: Theodore F. Craver, Jr., Chairman, President & CEO, Edison International, Electricity as a Transportation Fuel: Opportunities and Challenges James J. Piro, President and CEO, Portland General Electric, Public Policy Challenges Brian Wolff, Sr. Vice President, External Affairs, EEI Market Education and Customer Outreach Electricity as a Transportation Fuel: Opportunities and Challenges Electric transportation represents the most significant remaining chance to grow new load (or simply retain the current level). And, if properly managed, that load can be added in a way that increases the overall efficiency in generation, transmission, and distribution operations. Opportunities also exist for investments in distribution system upgrades needed to accommodate the new load, as well as providing sophisticated sensing, advanced protection and control systems, circuit designs, and grid stability devices to allow for twoway communication and power flows. We must remember that in one package a PEV combines multiple technologies that can not only help to develop new, better customer relationships and improve overall satisfaction, but that also are applicable to enabling grid modernization, including energy storage, bi-directional communications, self-metering, advanced control capabilities, automated diagnostics, and mobility. In addition to the operational benefits electric transportation can provide, this technology can also open the door to a variety of new business opportunities for utilities. Customers are conditioned to want to control their transportation energy costs and PEVs provide an increasingly sophisticated platform for innovation in value-added services (such as GPS, Bluetooth, entertainment systems, diagnostic alerts, and efficiency information). Based on the degree of electrification, grid connectivity, communications capability, and customer engagement interest, PEVs will be a catalyst for even more services. The company that owns the PEV energy relationship will have the inside track on other energy-related services. Electric Transportation EEI Fall Board and Chief Executives Meeting, September 2012 There is no question that the array of new and innovative technologies—advanced batteries for vehicles and storage; distributed generation; intelligent metering, appliances, and grids; bi-directional communication and power flow—has the potential to create a fleet of disruptive, interrelated technologies poised to fundamentally change the grid of today and the utilities that power it. Moreover, these emerging technologies present the opportunity for powerful, agile, and unregulated companies to get into the business that utilities have traditionally seen as near-exclusively their own: creating, storing, and managing energy. However, with these expected technological and business changes come new opportunities equal to the challenges. Utilities have an opportunity to engage with individual customers like never before, potentially providing more value than just reliable and affordable power. Instead of these new market entrants being competitive threats, they may present the chance to forge mutually beneficial partnerships. Indeed, these changes may even offer the possibility of updating and upgrading the regulatory process to make it more nimble, flexible, and constructive. Advocating for Positive Federal and State Public Policies There is a critical need for strong public policies that support and promote adoption of electric transportation technologies and the acceptance of electricity as a viable and cost-effective transportation fuel. Appropriate regulation and oversight will be crucial to help break down market barriers to the commercial-scale deployment of PEVs and related infrastructure. However, the regulatory implications of this technology can be complex and can change quickly, with many just beginning to come to light. Defining the right policy framework to support a sustainable, open and competitive market for electric transportation technologies, in a way that provides benefits and value to all customers, will be essential to ensuring the success of these technologies. Many state legislators are already taking action to enact policies that have a direct impact on the utility business. It is important for utilities to be engaged and to work with their state legislators and regulators to ensure these policies optimize benefits to customers and the utilities providing the fuel. EEI is currently working with its member companies and other stakeholders to promote favorable state policies that support the use of electricity as a transportation fuel and the role of the utility as the fuel provider. Areas of focus include the following policy issues:  Fuel taxes - As many states grapple with the shortfalls in needed revenue from traditional gasoline taxes and tolls, they are exploring new ways to more systematically, accurately, and fairly collect these necessary revenues, including having owners of PEVs, like those of all other vehicles, pay their fair share for the continued maintenance and upgrades of the roads they use. PEVs, however, should not be singled out for testing of these new systems, particularly in these relatively low-volume, nascent-market years, nor should their owners end up paying more than their gasoline-vehicleowning counterparts. Finally, electric utilities should not be burdened with the collection of new taxes on PEVs, as this likely will have unintended consequences for the rates of all customers.  Role of electric utilities in charging infrastructure - Electric utilities should not be precluded from participating in charging infrastructure activities that may include the owning, leasing, operating, or maintaining of electric vehicle supply equipment (EVSE). The serving electric utility should be the sole provider of electricity to EVSEs if the electricity is not generated independently on-site.  Status of third-party electric vehicle service providers (EVSPs) -EVSPs should not be regulated by state PUCs/PSCs as electric utilities. However, in the near future, there may be need for regulation and oversight from some state or federal agency on matters of safety, reliability, price gouging, data privacy, etc. 2 Electric Transportation  EEI Fall Board and Chief Executives Meeting, September 2012 Early Notification - A more systematic approach is needed to notify utilities early about customers purchasing PEVs or installing EVSEs. This will be of significant value to many utilities in their distribution system planning. Market Education and Communications Outreach Early PEV adopters are connecting online with other PEV owners and enthusiasts. While electricity as a fuel is implicit in these conversations, its intrinsic value is often not addressed directly, nor is the important role that utilities play in providing the fuel. Through a newly created, multi-faceted communications effort, EEI’s is working to expand the conversation beyond PEVs to the fuel source itself and to increase the visibility and acceptance of electricity as a transportation fuel. EEI also is working to position electric utilities as the companies that are making this technology viable for consumers. Solidifying the connection for consumers between utilities and PEVs will open new doors to engage consumers in new ways on related issues including other electric transportation applications, energy efficiency and management, and many more. EEI’s market education and communications outreach efforts will engage the core PEV enthusiasts to take action and to help us advocate for electricity as a fuel by sharing stories and information with their online and offline networks. This conversation will spill over to the fast-follower community of technology enthusiasts and individuals interested in PEVs who haven’t yet made the switch. Eventually, the momentum will build to reach all consumer audiences. The outcome of the communication efforts are expected to improve the level of engagement with current and future vehicle enthusiasts, increase the visibility and awareness of using electricity as a transportation fuel, refute myths and misinformation, and finally, garner broad acceptance for electricity as a transportation fuel. 3 State Legislative 2012 Update – Electric Transportation As states look to promote alternative fuel vehicles, they are creating a variety of incentives; ranging from high-occupancy vehicle lane exemptions to financial incentives including tax credits and exemptions and parking incentives. However, they are also exploring bigger policy challenges including; how to treat a (re)seller of electricity for the purpose of electric vehicle charging, and how to recoup traditional gasoline fuel taxes from electric utilities and other alternative fuel providers. . Many of these policy questions directly affect utility operations and business strategies, beyond electric transportation. Given the amount of legislative activity, as demonstrated below, it is important for the electric utility industry to be engaged on these issues. In 2012, nineteen electric/alternative fuel vehicle-related bills have been enacted into law. Many more bills were considered and either failed or were overhauled. Below is a summary of this activity, with bills of particular importance for the utility industry in bold. Legislation Passed State Bill Action California S.B. 880 Colorado H.B. 1258 Florida H.B. 7117 Georgia H.B. 868 Hawaii H.R. 155 Hawaii S.B. 2746 Hawaii S.B. 2747 Kansas H.B. 2455 Authorizes the installation of an EV charging station in a common areas (with restrictions). Exempts sellers of electricity as fuel for AFVs from regulation as a public utility. Provides that electric vehicle charging to the public by a nonutility is not the retail sale of electricity and that such service providers are not subject to specified regulation. Provides loans, grants, or rebates to residential or commercial property owners who make “energy efficiency improvements” – including EV charging equipment. Makes manufacturers of electric vehicle enterprises eligible for the ‘business enterprise’ tax credit. Requests the Dept. of Business, Economic Dev. & Tourism to determine financing mechanisms to assist private parking lot owners with the costs associated with providing charging units for EVs. Authorizes the DOT to adopt rules for the registration of, and issuance of license plates for, EVs. Exempts EVs from parking fees under certain conditions. Allows EV parking stall with charging system to be located anywhere in the parking lot/structure but prohibits parking spaces designated for EVs from displacing/reducing ADA stalls. Directs the DOT to engage public/stakeholders in a dialogue about the long-term feasibility of relying on the motor fuel tax Louisiana H.B. 1213 Maryland H.B. 1279 Maryland H.B. 1280 New Hampshire H.B. 1144 North Carolina H.B. 177 South Carolina H.B. 3059 Vermont H.B. 770 Virginia H.B. 85 Virginia S.B. 485 Virginia S.B. 639 Washington H.B. 2545 as the primary mechanism of funding the state’s highway maintenance/construction program and as the major contributor to state/local transportation budgets. Requires the DOT to report findings by Jan. 1, 2014. Provides for the purchase or lease of alternative fuel vehicles by state agencies. Allows for the disclosure of personal information from the MVA for use by an electric company for use in electric power supply availability and reliability. Alters the definition of electricity supplier to exempt a person or station service provider who owns or operates EV charging equipment. Establishes a Commission to study the taxation of alternative fuel and electric-powered motor vehicles for the purpose of funding improvements to the state’s highways and bridges. Establishes an Interagency Task Force to evaluate the costs associated with AFV purchase, projected fuel, operations and maintenance, and necessary fueling infrastructure in addition to environmental considerations to recommend best fleet options for state agencies. Allows the NC DOT to install EVSE at state rest areas and to charge a fee for usage. Revises definition of plug-in hybrid vehicle; raises the aggregate amount of the plug-in hybrid vehicle tax credit available each fiscal year and deletes its expiration date; and provides that the credit must be allocated to eligible claimants during a fiscal year on a firstcome, first-serve basis. Directs the DOT, in consultation with other specified state agencies, to analyze options for user fees and fee collection mechanisms for motor vehicles that rely on energy sources not currently taxed so as to contribute to the transportation fund. Extends sunset provision of HOV lanes use by vehicles with clean special fuel license plates. Establishes the Alternative Fuel Vehicle Conversion Fund to assist state agencies with the cost of converting to an alternative fuel vehicle fleet. Establishes an annual $50 license tax for electric motor vehicles registered in the Commonwealth. Allows local governments and state agencies to substitute CNG, LNG, and propane for electricity or biofuel in satisfying their fuel usage requirements, if the DOC determines that electricity and biofuel are not reasonably available. Other States that Considered Legislation  Alabama  Illinois  Mississippi  Connecticut  Minnesota  New Jersey Note: many of the states with passed legislation also had additional bills that failed. Sources: NEMA, Stateside Alerts EPA GHG Vehicle Standards – Electric Transportation In late August, the U.S. Environmental Protection Agency (EPA) and the U.S. Department of Transportation’s National Highway Traffic Safety Administration finalized corporate average fuel economy (CAFE) standards and Greenhouse Gas (GHG) standards for light-duty vehicles including passenger cars, light-duty trucks and medium-duty passenger vehicles for model years (MY) 2017-2025. EPA’s GHG standards included incentives for auto manufacturers that produce and sell alternative-fueled vehicles including electric vehicles (EVs), plug-in hybrid electric vehicles (PHEVs), fuel cell vehicles (FCVs) and compressed natural gas (CNG) vehicles. EPA’s GHG standards included incentives for auto manufacturers for alternativefueled vehicles including electric vehicles (EVs), plug-in hybrid electric vehicles (PHEVs), fuel cell vehicles (FCVs) and compressed natural gas (CNG) vehicles. In proposing the incentives, EPA noted that EVs have the potential to be “game changers” with respect to reduced dependence on oil and reduced emissions from the transportation sector. But, in the proposed rules EPA stated that, in the near term, EVs are “worse” than conventional vehicles because of the estimated “upstream” emissions related to electricity generation. EPA included two types of incentives for EVs and other alternative-fueled vehicles. o First, EPA created an “incentive multiplier” for alternative-fueled vehicles sold in MYs 2017-2021. These vehicles will “count” as more than one car for the purpose of demonstrating compliance with the rule. EVs and FCVs have a larger multiplier than PHEVs and CNGs. o Second, for MYs 2017-2021, every EV, PHEV (operating in electric mode) and FCV sold would be counted as emitting 0 g/mile of tailpipe pollution. For MYs 2022-2025, the use of the 0 g/mile compliance value would be capped. Any sales above a company-specific cap will have to account for estimated “upstream emissions” associated with electricity generation, using an upstream emissions factor established by the rule. In comments on the proposed standards, EEI largely supported the proposed EV incentives, but objected to EPA’s characterization of the current benefits of increased EV deployment. EEI’s comments also objected to EPA’s proposal to “discount” some of the incentives for EVs in MY 2022-2025 to reflect the “upstream” GHG emissions associated with electricity generation. EEI objected both to the use of upstream emissions generally, as well as to the specific methodology that EPA used to discount the incentives. In the final rule, EPA took several steps to address EEI’s concerns. o First, EPA revised the upstream national emissions factor downward significantly to reflect expected changes in the fleet, given lower natural gas prices and new regulations. o Second, EPA tried to address charging patterns in the modeling and recognized that regional differences in the generation mix – especially in those areas likely to see earlier higher EV deployment rates – will impact estimated upstream GHG emissions. o EPA also noted that the Agency will revisit the national upstream issue in 2017, when doing a required mid-term review. As EEI advocated, EPA recognized for the first time the value of EVs in reducing GHG emissions today. Included in the final rule was a chart that compared the tailpipe and upstream emissions of a MY 2012 gasoline Honda Civic, a Civic CNG and a Leaf EV. When comparing “total” emissions (actual tailpipe and estimated upstream), the Leaf beats both the CNG vehicle and the conventional fueled vehicle, using either the estimated California (lesser) upstream emissions values or the estimated national upstream emissions values. The table, taken from the final EPA GHG vehicle standards, is below: Table III-16 Tailpipe and Upstream GHG Emissions Comparison – MY 2012 (grams per mile) (values in parentheses are relative to Civic Gasoline) Civic Gasoline Civic CNG 163 (-21%) Tailpipe 207 Upstream 58 67 Tailpipe + Upstream 265 230 (-13%) Leaf EV 0 (-100%) 96 to 156 (CA and US) 96 to 156 (-64% to -41%) SMART GRID RAPID RESPONSE EEI Fall Board and Chief Executives Meeting, September 2012 Implementation of smart grid technologies continues to grow rapidly in the U.S. utility space, and 36 million smart meters are now installed across all 50 U.S. states—with plans to reach 65 million meters by the end of 2015. That swift trajectory also has been met with significant pockets of resistance in a number of states as self-styled activists object to purported concerns regarding health and privacy. In late 2011, EEI launched its Smart Grid Rapid Response program, which is designed to quickly and effectively counter specious claims made about smart meters wherever they appear. In concert with member companies, EEI has retained highly credentialed experts in the fields including radio frequency (RF) and privacy to be the face of our industry in responding forcefully and quickly to protests that are launched in the news media, social media and elsewhere. In recent months, EEI’s panel of experts have done a number of media interviews to rebut falsehoods about smart meters, and they also have testified in state regulatory proceedings about the impacts of advanced metering infrastructure. We expect that work to expand in the year to come. EEI Board Lead: Brian Wolff, Sr. Vice President, External Affairs, Edison Electric Institute Smart Grid Rapid Response Program Brian L. Wolff Senior Vice President, External Affairs Edison Electric Institute EEI Chief Executive Officers and Board of Directors Meeting September 13, 2012 The Challenges At PUC Hearing, a Push for Smart Meter Opt-Out Plan California Activists Want Smart Meters Banned, Claim They’re Bad for Health ‘Smart’ Meters Draw Complaints of Inaccuracy Communications Campaign  Sequenced, coordinated campaign with four phases guided by member company advisory working group Research Message Development Toolkit External Advocacy Resources for Understanding the Modern Grid  SmartGrid.eei.org  Public-facing, consumer- focused online communications resource  Members-only Online Communications Toolkit  Rapid Response Team  Company Collaterals  EEI Messages & Materials  Exclusive Research Smart Grid Rapid Response Program  Third-party experts who can assist electric companies’ communication efforts by providing independent, credible analyses of key issues related to the smart grid and smart meters:  Speaking to the media  Testifying in regulatory proceedings  Writing technical papers on your behalf  Areas of expertise:  Radio frequency  Privacy  Opt-out  Emerging technology concerns Member Experiences BOARD OF DIRECTORS DRAFT EDISON ELECTRIC INSTITUTE MINUTES OF THE BOARD OF DIRECTORS QUARTERLY AND ANNUAL MEETINGS June 5, 2012 A regular meeting of the Board of Directors and an Annual Meeting of the Edison Electric Institute were held at the J.W. Marriott Grande Lakes Hotel in Orlando Florida on June 5, 2012. Mr. Thomas Farrell, EEI Chairman and Chairman, President and CEO of Dominion, presided and called the regular meeting to order at 3:00 p.m. Directors Present Thomas F. Farrell, II, Outgoing Chairman Lewis Hay III, Incoming Chairman William D. Johnson, Vice Chair Theodore F. Craver, Jr., Incoming Vice Chair Michael W. Yackira, Incoming Vice Chair Anthony F. Earley, Jr., Chairman Emeritus James E. Rogers, Chairman Emeritus Gregory Abel Nicholas Akins Bradley Beecher Jerome Benkert for Carl Chapman Paul Bonavia Donald Brandt Kevin Burke Michael Chesser Christopher Crane Margaret Felts for Philip Barnhard Thomas Fanning Benjamin Fowke Phil Herrington Alan Hodnik Christopher Johns Charles Jones for Anthony Alexander Patricia Kampling Thomas King Ralph LaRossa for Ralph Izzo Scott Morris John Procario John Ramil Lawrence Reilly Richard Riazzi Joseph Rigby Richard Rosenblum for Constance Lau Mark Ruelle Charles Schrock Thomas Standish for David McClanahan James Torgerson Patricia Vincent-Collawn Thomas Voss Kevin Walker for Robert Kump Kenneth Zagzebski EEI Officers Present Thomas R. Kuhn David K. Owens Brian L. Wolff Edward H. Comer James P. Fama Brian V. McCormack Richard F. McMahon Mary D. Miller John S. Schlenker Quinlan J. Shea Kathryn A. Steckelberg 1. Mr. Farrell initiated the meeting by announcing new CEOs since the last Board meeting in March. He indicated that since the merger between Northeast Utilities and NSTAR has been finalized, Mr. Thomas J. May is now President and CEO of the merged company and Mr. Charles W. Shivery is Non-Executive Chairman. Mr. Phil Herrington is the new President and CEO of AES subsidiary Dayton Power and Light Co. Mr. Eric Silagy became the new President and CEO of Florida Power & Light Co. on May 5. Mr. Terry D. Bassham became President and CEO of Great Plains Energy, Inc. on May 31, replacing Mr. Michael J. Chesser, who will continue as Chairman. Mr. Denis P. O’Brien has become CEO of Exelon Utilities following the merger of Exelon and Constellation. Mr. Craig L. Adams succeeds Mr. O’Brien as President and CEO of PECO. Ms. Margaret E. Felts has become President of Mt. Carmel Public Utility Co. and is attending her first EEI Board meeting. 2. Mr. Farrell called attention to the Antitrust Guidelines and indicated that the Secretary had informed him that a quorum was present. 3. Moving to the business portion of the Board meeting, the minutes of the March 20-22, 2012, Board meeting were approved. 4. Mr. Lewis Hay III, Vice Chair of EEI and Chairman and CEO of NextEra Energy, Inc., reported that Mr. John Langan, the audit engagement partner at Clifton Larson Allen, EEI’s auditor, had met with the Executive Committee and provided a clean audit opinion. Mr. Hay also indicated that EEI had already collected 100% of its dues and was on track for a balanced budget. Mr. Hay reported on new and departing associate and international members. Finally, Mr. Hay reported that the Membership and Budget Committee has approved, as a new guideline, that the dues will follow annual inflation increases in the Consumer Price Index (CPI), and that the Committee recommended a 3.2% increase in dues for 2013 based on the 2011 CPI. The Membership and Budget reports and recommendations (Tabs A and B) were approved. 5. Ms. Maurie Dugger, EEI Senior Director, Political Affairs, provided the PowerPAC Report and discussed the PAC Charitable Match program as a tool for member companies to consider. 2 6. Mr. Farrell reported that EEI had ranked very highly in a National Journal survey of effective associations and corporations in Washington. Mr. Farrell asked EEI President Mr. Thomas R. Kuhn to provide a brief overview of issues before the meeting moved to individual reports. Mr. Kuhn reminded members how the industry has been able to move forward in a united way on major issues. Mr. Kuhn reported we were making good progress on Dodd-Frank, energy saving performance contracts and EPA’s 316(b) rule and indicated there was much more work to do on environmental, FERC, electric vehicles and, particularly, on cybersecurity and dividend issues. He emphasized the importance of participating in the Defend My Dividend campaign. Mr. Kuhn also elaborated on the significance of the National Journal survey of the most influential associations and companies in Washington and the fact that EEI ranked in the top quarter of every quality evaluated by the National Journal. 7. Mr. Farrell called on Mr. Thomas A. Fanning, Chairman, President and CEO of Southern Company and EEI Senior Vice President, External Affairs, Mr. Brian L. Wolff, to talk about the Defend My Dividend (DMD) campaign. Mr. Fanning indicated the importance of linking the tax rates associated with dividends and capital gains because they both relate to capital formation and of arguing that these rates should be as low as possible. He described the major elements of the DMD campaign and encouraged CEO visits to their congressional delegations during the summer. Mr. Fanning thanked EEI Vice President of Finance and Energy Supply Mr. Richard F. McMahon and EEI Vice President of Government Relations Ms. Kathy Steckelberg for their efforts. Mr. Wolff elaborated on the outreach elements of the DMD campaign and showed supportive television interviews and planned advertisements. 8. Mr. Farrell called on Mr. Theodore F. Craver, Jr., Chairman, President and CEO of Edison International, to discuss financial issues. Mr. Craver indicated that the industry has made significant progress, noting the major win when CFTC issued final rules in April on swap and swap dealer definitions. Mr. Craver thanked Mr. McMahon for an outstanding job leading EEI’s efforts. He indicated, for example, that the swap dealer definition’s de minimis exemption was raised from $100 million to $8 billion for a phase-in period and eventually to $3 billion, and excluded swaps between affiliates. He expressed optimism that the end-user rule expected this summer would be similarly successful. 9. Mr. Farrell called on Mr. William D. Johnson, Chairman, President and CEO of Progress Energy, to report on environmental matters. Mr. Johnson indicated that EPA’s proposed greenhouse gas (GHG) NSPS standard is based on emissions from a combined cycle natural gas plant. He indicated that EEI would file comments by June 27. On section 316(b), he indicated that EPA had issued a Notice of Data Availability that identified many of the options that the industry had been discussing and that EPA would soon issue more detail on its willingness-to-pay study, used to value the benefits of the rule. Mr. Johnson reported some signs of progress on regional haze issues, under the leadership of Ms. Patricia K. Vincent-Collawn, Chairman, President and CEO of PNM Resources, Inc. As for coal ash regulation, Mr. Johnson stated that the House had 3 passed a good bill and efforts were being made to attach it to a Senate bill. Finally, he encouraged members to act early for EPA MACT implementation. 10. Mr. Farrell called on Mr. Gregory E. Abel, Chairman, President and CEO of MidAmerican Energy Holdings Co., and Ms. Vincent-Collawn to discuss FERC transmission matters. Ms. Vincent-Collawn reported on EEI efforts to encourage continuation of and refute misstatements about FERC’s transmission incentive policy. She also encouraged more CEO involvement at FERC. Mr. Abel, reporting on Order No. 1000’s transmission planning and cost allocation policy, indicated that a recent Order on Rehearing made some progress, but that the Board needed to consider litigation. He called on Mr. James P. Fama, EEI Vice President of Energy Delivery, who indicated that about 60 requests for rehearing and/or clarification were mostly rejected by FERC. Mr. Fama recommended EEI appeal Order No. 1000, focusing on three issues: (1) the requirement that an incumbent transmission owner step in to “mitigate” any 3rd party default on a commitment to build; (2) elimination of the right of first refusal for reliability projects; and (3) failure to invoke FERC authority to apply Order No. 1000 planning and regional cost allocation requirements to non-jurisdictional utilities. After discussion, Mr. Farrell indicated that there was a consensus for EEI to appeal. 11. Mr. Farrell called on EEI Executive Vice President of Business Operations Mr. David K. Owens to talk about developments involving NERC. Mr. Owens indicated that while Version 3 of NERC’s CIPS Standards are currently in effect, Version 4 has been approved and goes into effect April 2014. In addition, FERC has set a March 31, 2013, deadline for NERC to file new Version 5 CIPS standards. Mr. Owens encouraged members to continue to show leadership in resolving and approving issues related to Version 5 and in reaching out to public power and other non-utility members of NERC to obtain support for a yes vote in September 2012. In response to a question from Mr. Christopher M. Crane, President and CEO of Exelon Corp., Mr. Gerry W. Cauley, President and CEO of NERC, indicated that Version 5 is meant to cover the bulk electric system on a prioritized scale, not distribution assets. Mr. Farrell asked Mr. Owens to follow up by sending the CEOs a summary of the issues at stake and a list of the members of the NERC drafting team. Referencing the FERC audit of NERC, Mr. Owens indicated that it is important to support transparency in the NERC process, but not micromanage the details. 12. Mr. Owens asked Mr. James P. Torgerson, President and CEO of UIL Holdings Corp., to discuss the Threat Scenario Project. Mr. Torgerson indicated that 46 members were participating in this project and encouraged more participants. He also indicated that there would be a meeting at the end of July to exchange best practices. 13. Mr. Farrell called upon Mr. Craver to discuss the new electric vehicle campaign. Mr. Craver reported that the electrification of transportation represents a big opportunity, although it is still at its very early stages. He reported on activities at EEI’s Powering the People conference; a meeting between Mr. James J. Piro, President and CEO of Portland 4 General Electric and Mr. Carlos Ghosn, Chairman and CEO of Nissan and Renault at the New York Auto Show; a public policy-maker discussion on emerging transportation issues attended by several hundred people, including the U.S. Secretary of Transportation, Mr. Raymond LaHood; and Electric Vehicle Symposium 26, attended by over 5,000 people. He explained the importance of educating the public about the benefits of the electrification of transportation, which would focus on the strengths of electricity as a fuel source and would mesh well with EDTA’s campaign on electric vehicles. Mr. Craver introduced Mr. Wolff, who described the efforts that EEI is conducting to understand the best ways to affect consumer behavior and decisionmaking. He suggested that the campaign, which will be called “Drive the Charge,” will try to engage the enthusiasm of the early adopters of electric vehicles. 14. Mr. Farrell called upon Mr. Michael Yackira, President and CEO of NV Energy, to discuss the Institute for Energy Efficiency (IEE). Mr. Yackira reported on a Partner Roundtable with 22 technical vendors and the Management Committee meeting of IEE on June 4. Presentations were made by Ms. Susan N. Story, President and CEO of Southern Company Services Inc., on Grid Modernization, Mr. Joseph M. Rigby, Chairman, President and CEO of Pepco Holdings, Inc., on Energy Efficiency and Customer Energy Management and Mr. Kevin Burke, Chairman, President and CEO of Consolidated Edison Inc., on Demand Response. Mr. Robert C. Rowe, President and CEO of NorthWestern Energy, is nominated to become Co-chair of IEE (replacing Mr. Yackira) along with Mr. Peter B. Delaney, President, Chairman and CEO of OGE Energy Corp. 15. Mr. Farrell called on Ms. Story, who reported on the Center for Energy Workforce Development (CEWD). Ms. Story thanked Mr. Robert P. Powers, COO of American Electric Power, for his leadership as Chairman at CEWD and recognized Mr. Thomas H. Graham, President, Pepco Region of Pepco Holdings Inc., as the new Vice-chair of CEWD. She reported that CEWD not only helps to replace retiring employees, but also provides education on the new technologies being installed throughout the system. She reiterated the importance of engaging community involvement. She provided an update on the five pilot programs for the Troops to Energy project; the groups being targeted as a result of grants from the Gates Foundation to promote diversity; and Math Boot Camp efforts. Finally, she encouraged members to provide CEWD and others reports on their success stories involving employee training and recruitment. 16. Mr. Henry A. Courtright, Senior Vice President, Member and External Relations of EPRI, provided a report on EPRI activities. He highlighted a May 31 report discussing cost savings that would result from more flexible ways to comply with various EPA rules and discussed related outreach activities. He also reported on the status of 15 programs, providing detailed information about costs and benefits of Smart Grid-related programs, and encouraged members to attend the EPRI Summer Seminar on August 6 and 7, covering Smart Energy, generation technologies and grid resiliency. 5 17. Mr. Marvin S. Fertel, President and CEO of the Nuclear Energy Institute, reported on changes in the composition of the Nuclear Regulatory Commission, provided an update on Fukushima-related activities to address Tier One lessons learned and related matters, and the status of the nuclear waste fee in light of related litigation. 18. Mr. Clair Goddard, Vice President, Plant and Corporate Evaluations of the Institute of Nuclear Power Operations (INPO), reported on INPO activities by noting that the transition from Adm. James Ellis to new President and CEO Adm. Bob Willard was complete. He described INPO’s post-Fukushima activities and its domestic nuclear activities. 19. Mr. Farrell thanked the members of the Board for their assistance during his year as Chairman. He remarked on the willingness of the members to work hard to resolve issues as well as the high quality of the EEI staff. 20. Mr. Farrell then moved into the Annual Meeting. The slate of Board members nominated (Tab D) was approved unanimously. Mr. Anthony F. Earley, Jr., Chairman, President and CEO of PG&E Corp., moved the nomination of Mr. Hay as Chairman of EEI and Mr. Yackira, Mr. Johnson and Mr. Craver as Vice-chairmen. The nominations were approved. 21. Mr. Hay took over presiding the meeting, promised to do his best to meet the high standards of prior Chairmen, asked for feedback from the members and expressed confidence for future success. 22. The full Executive Committee membership (Tab E), including new members Mr. Nicholas K. Akins, President and CEO of American Electric Power, Mr. Crane, Mr. Benjamin G.S. Fowke III, Chairman, President and CEO of Xcel Energy, and Ms. Vincent-Collawn, was approved. The Board further approved the appointment of new Board and Policy Committee members (Tab F), including Mr. Fowke to join Mr. Fanning and Mr. Craver as Co-chairs of the Policy Committee on Finance; Mr. Gerard M. Anderson, Chairman, President and CEO of DTE Energy Co., to join Dr. Ralph Izzo, Chairman, President and CEO of Public Service Enterprise Group, Inc., as Co-chair of the Policy Committee on Environment & Climate; Mr. Anthony J. Alexander, President and CEO of FirstEnergy Corp., to join the Policy Committee on Supply; Mr. Earley to join Mr. Piro and Mr. Craver as Co-chairs of the CEO Task Force on Electric Transportation; Mr. Gale E. Klappa, Chairman, President and CEO of Wisconsin Energy Corp., to join Mr. David M. McClanahan, President and CEO of CenterPoint Energy Inc., as Co-chair of the CEO Task Force on Natural Gas; and Mr. Rowe as a new Co-chair of the Institute for Electric Efficiency. 23. The Board also approved the directors of the Center for Energy Workforce Development (Tab G) and the Edison Foundation (Tab H). 6 24. Finally, the Board approved a Resolution (Tab I) saluting the contributions of Mr. Farrell as Chairman. Mr. Hay highlighted the resolution and presented Mr. Farrell with the resolution and a bronze Edison plaque. He offered his personal congratulations. A presentation of gifts followed. The meeting was adjourned shortly after 5:00 p.m. 7 TREASURER’S REPORT EEI Fall Board and Chief Executives Meeting, September 2012 The 2012 regular activities balanced budget reflects total income and gross operating expense of $63.9 million. As of August 15, 2012, $49.9 million of the dues budget and $9.3 million from meetings, publications, investment income, and associate and international affiliate dues has been collected, which represents 100% of the year to date budget. The attached Statement of Operations provides a more detail picture of the current year to date results, which are consistent with the same period last year. Separately Funded Activities, primarily supported by member companies on a voluntary basis, amount to approximately $9 million for 2012. The audits of the Institute’s Retirement Income Plan and Cooperative Savings Plan, for the plan year ended December 31, 2011, are currently in progress and are on schedule to be completed later this summer. The financial statements for both plans are presented in compliance with the Department of Labor’s requirements in accordance with the Employee Retirement Income Security Act of 1974 (ERISA). As always, copies of the Institute’s audited financial statements (clean opinion) and IRS Form 990, which were both presented to the Executive Committee by CliftonLarsonAllen at the June, 2012 meeting, are available upon request. Edison Electric Institute Regular Activities Statement of Operations (Unaudited) 2012 Budget Revenues: Electric company dues Programs, publications and meetings Investment income International affiliate dues Associate member dues Total dues and revenues $ Expenses: Salaries Employee benefits Programs, publications and meetings General office and administrative Total expenses Net Operating Income As of August 15, 2012 Budget Actual 49,692,000 8,560,000 3,200,000 1,450,000 1,026,000 63,928,000 $ 24,518,000 12,444,000 18,388,000 8,578,000 63,928,000 $ - $ YTD Actual % of Budget 49,692,000 5,194,000 2,083,000 1,325,000 901,000 59,195,000 $ 49,937,000 5,207,000 2,080,000 1,107,000 933,000 59,264,000 100.1% 15,324,000 7,778,000 11,930,000 5,361,000 40,393,000 14,886,000 8,108,000 10,173,000 5,465,000 38,632,000 95.6% 18,802,000 $ 20,632,000 Edison Electric Institute Separately Funded Activities Statement of Expenses (Unaudited) 2012 Budget Fund Description Industry Issues SFA (2) $ Employment Testing As of August 15, 2012 Budget Actual (1) 4,700,000 $ 2,937,000 $ 3,322,000 1,467,000 917,000 870,000 Environmental SFA (3) 890,000 556,000 359,000 Restore Power 259,000 162,000 166,000 AVIAN Power Line 204,000 127,000 99,000 Spare Transformer 198,000 124,000 135,000 Water Advocacy Coalition 132,000 83,000 67,000 Total SFA Expense, net of U-Groups $ 7,850,000 $ 4,906,000 $ 5,018,000 Funds not controlled by EEI Utility Air Regulatory Group 8,100,000 5,063,000 5,659,000 Utility Solid Waste Activities Group 3,267,000 2,042,000 2,049,000 Notes: (1) All SFA budgets are estimates and are subject to available funds contributed on a voluntary basis. (2) The EEI Board approved a 10% voluntary assessment, based on dues, for the Industry Issues SFA. (3) The EEI Board approved a voluntary assessment, based on fossil fuel generation, for the Environmental SFA. EEI Membership Report To the EEI Board of Directors September 2012 1) Domestic Member Addition We are pleased to inform you that SCANA Corporation has applied for Domestic Membership. Headquartered in central South Carolina (in Cayce, near the capital city of Columbia), SCANA is an energy-based holding company whose businesses include regulated electric and natural gas utility operations, telecommunications, and other businesses. SCANA’s subsidiaries serve electric customers in South Carolina and natural gas customers in South Carolina, North Carolina and Georgia. SCANA’s principal subsidiary, South Carolina Electric & Gas (SCE&G), is a regulated public utility engaged in the generation, transmission, distribution and sale of electricity to approximately 668,000 customers in a service area covering nearly 17,000 square miles in the central and southern portions of South Carolina. SCE&G also provides natural gas to over 300,000 customers throughout South Carolina. SCANA has about 6,000 megawatts of electric generating capacity; almost half is coal fired, and one-quarter gas fired. They operate (and own the majority of) the VC Summer nuclear plant, and in March received the construction and operation license to build two more nuclear units. 2) International Affiliate Member Changes We are pleased to announce that two companies have applied for International Affiliate Membership: Jamaica Public Service (JPS), with a customer-base of nearly 600,000, is the sole distributor of electricity in Jamaica; with generation capacity that exceeds 620 megawatts, utilizing steam (oil-fired), gas turbines, combined cycle, diesel, and hydroelectric technologies. JPS operates 27 generating units (including eight hydro and one wind farm), 54 substations, and own approximately 14,000 kilometers of distribution and transmission lines. JPS is owned by four entities: Marubeni Caribbean Power Holdings Inc., and Korea-East West power, with 40 percent ownership each; the Government of Jamaica owning most of the remaining shares; and a small group of minority shareholders maintains a less than one percent stake. Swissgrid is the national grid company, and in its capacity as transmission system operator it ensures the secure, reliable and cost-effective operation of the Swiss high-voltage grid. Swissgrid employs more than 350 people at its sites in Laufenburg, Frick and Vevey. As a member of the European Network of Transmission System Operators for Electricity (ENTSO-E), it is also responsible for coordination and grid usage in the cross-border exchange of electricity in Europe. Swissgrid is wholly owned by the eight Swiss electricity companies. Additionally, we regret to inform you that we have one company withdrawing from membership due to a change in ownership: Tatapower-ddl, formerly North Delhi Power (India). With these changes, EEI will have 83 International Affiliates. 3) Associate Member Changes We are pleased to inform you that we have received seven applications for Associate Membership. COMPANY a) Motorola Utility Solutions Mike Koch Energy Market Principal Schaumburg, Ill. BUSINESS Information technology EEI Membership Report Page Two September 2012 b) Normandeau Associates Robert Bibbo Vice President Bedford, N.H. Environmental consulting and services c) Parker Poe Adams & Bernstein, LLP J. Ashley Cooper Partner Charleston, S.C. Law Firm d) Parsons Corp. Randy Britt Director of Sustainability Pasadena, Calif. Engineering and construction e) Pillsbury Winthrop Shaw Pittman LLP Law firm J. Anthony Terrell Partner New York, N.Y. 10036 f) PowerPlan, Inc. Lake Wilson Sales & Marketing Coordinator Atlanta, Ga. g) Robin M. Nuschler, Esq Robin Nuschler Sole Proprietor Fairfax, Va. Financial and accounting Legal practice in electric utility regulation These additions are offset by several Associate Members that have dropped their EEI membership due to financial hardship, mergers, and change in line of business: AlertEnterprises Inc.; CURRENT Group; Intelligent Access Systems: Peabody Energy; SunPower Corporation; and Westinghouse Electric. With these changes, EEI will have 247 Associates. Table of Contents Treasurer’s Report .................................................................... ……………..2 Steering Committee ...……………………….……………………………..…...3 2012 Individual Contribution………………………………..……………..4 2012 PAC to PAC Contributions ..................................... ……………....11 2012 Disbursements .................................................................................. 12 1 Treasurer’s Report September 2012 Treasurer’s Report 2012 Election Cycle – 1/01/2011 through 08/16/2012 Receipts PAC to PAC Contributions CEO and Member Company Executive Contributions Washington Representatives EEI Employee Contributions Total Election Cycle Receipts $265,500.00 $350,200.00 $35,525.00 $104,740.10 $755,965.10 Disbursements Contributions to Candidates $401,000.00 Other Contributions $339,000.00 2010 General – Debt Retirement $2,500.00 Summary Receipts Cash on Hand Year End 2010 Disbursements $755,965.10 $18,326.45 $742,500 September 2012 Cash on Hand $31,791.55 2 2012 PowerPAC Steering Committee Eric Grey Ann Pride WE Energies Chairman Entergy Chairman Emeritus Chris Hickling Kristen Ludecke EEI PSEG Robbie Aiken Kelly Chapman Pinnacle West Dominion Alicia Cannon Chris Mathey AEP Exelon Mike Poling Emily Fisher Great Plains Energy EEI Jessica Hogle Shaun Garrison PG&E Ameren Corp Kelly Eaton Maurie Dugger NextEra Energy Treasurer, PowerPAC 3 2012 Individual Contributions The following individuals have contributed up to $5,000 to PowerPAC since January 1, 2012 Name Greg Abel Nick Akins Tony Alexander Don Brandt Mike Chesser David Christian Chris Crane Ted Craver Tony Earley Tom Fanning Tom Farrell Ben Fowke Lew Hay Ralph Izzo Thomas King Tom Kuhn David McClanahan David Owens Don Robinson Jim Rogers Mayo Shattuck Quin Shea Pat Vincent-Collawn Tom Voss Michael Yackira John Young Company MidAmerican Energy Holdings American Electric Power FirstEnergy Pinnacle West Capital Corporation Great Plains Energy Dominion Exelon Edison International PG&E Corporation Southern Company Dominion Xcel Energy NextEra Energy PSEG National Grid Edison Electric Institute CenterPoint Energy Edison Electric Institute Arizona Public Service Company Duke Energy Exelon Corporation Edison Electric Institute PNM Resources Ameren NV Energy Energy Future Holdings 4 2012 Individual Contributions The following participants have contributed or made a commitment of at least $2,000 to PowerPAC since January 1, 2012 Name Scott Aaronson Paul Bonavia Kevin Burke Carl Chapman Daniel Cole Ed Comer Peter Delaney Maurie Dugger John Easton Bill Harvey Al Hodnik Chris Johns Brian McCormack Richard McMahon Mary Miller Scott Morris Mark Planning John Ramil Joseph Rigby Mark Ruelle John Russell John Schlenker Charlie Schrock William Spence Kathy Steckelberg Brian Wolff Company Edison Electric Institute UNS Energy Corp. ConEdison Vectren Corp. Ameren Services Edison Electric Institute OGE Energy Edison Electric Institute Edison Electric Institute Alliant Energy ALLETE PG&E Corporation Edison Electric Institute Edison Electric Institute Edison Electric Institute Avista Corporation Edison Electric Institute TECO Energy Pepco Holdings Westar Energy CMS Energy Edison Electric Institute Integrys Energy PPL Corporation Edison Electric Institute Edison Electric Institute 5 2012 Individual Contributions The following participants have contributed or made a commitment of at least $1,000 to PowerPAC since January 1, 2012 Name Robbie Aiken Warner Baxter Bradley Beecher David Brown Dan Chartier Alex DeBoissiere Jim Fama Bill Fang David Gilbert Barbara Hindin Eric Holdsworth Tony Ingram Paul Kaleta Patricia Kampling Connie Lau Ron Litzinger Sarah Novascone Gregory Obenchain Cal Odom Jim Piro Ann Pride Lawrence Reilly Rick Tempchin Jim Torgerson Sam Tornabene Dan Turton William Von Hoene Company Pinnacle West Capital Corporation Ameren Corporation Empire District Electric Company Exelon Corporation Edison Electric Institute United Illuminating Holding Company Edison Electric Institute Edison Electric Institute Exelon Corporation Edison Electric Institute Edison Electric Institute Edison Electric Institute NV Energy Alliant Energy Hawaiian Electric Industries Southern California Edison Edison Electric Institute Edison Electric Institute Edison Electric Institute Portland General Electric Entergy Central Vermont Public Service Edison Electric Institute United Illuminating Holding Company Edison Electric Institute Entergy Exelon Corporation 6 2012 Individual Contributions The following participants have given personal contributions up to $1,000 to PowerPAC since January 1, 2012 Name Anthony Alexander, Jr. David Arthur David Baker Carolyn Barbash Robert Bartlett Jerome Benkert Kevin Bethel Dale Bodden Ken Bohlen Cari Boyce Karen Britto Bruce Bullock Michael Carano Jackie Carney Rick Carter Kelly Chapman Caroline Choi Ronald Christian Alice Cobb Jeffrey Corbett Kiran Crout Denise Danner Darnell DeMasters Roberto Denis Pat Dinkel Vincent Dolan William Doty Mike Eckard David Falck Ed Fox Daniel Froetscher Kevin Geraghty Herb Goforth Barbara Gomez Company FirstEnergy Corporation PPL Corporation CenterPoint Energy NV Energy Alliant Energy Corp. Vectren Corp. NV Energy CenterPoint Energy Arizona Public Service Company Duke Energy DTE Energy NV Energy NV Energy Exelon Corporation National Grid Dominion Southern California Edison Vectren Corp. NV Energy Duke Energy CMS Energy Arizona Public Service Company Wisconsin Energy NV Energy Arizona Public Service Company Duke Energy Vectren Corp. FirstEnergy Pinnacle West Capital Corporation Arizona Public Service Company Arizona Public Service Company NV Energy NV Energy Arizona Public Service Company 7 2012 Individual Contributions The following participants have given personal contributions up to $1,000 to PowerPAC since January 1, 2012 Name Frank Gonzales Allison Graves Eric Grey Jeff Guldner David Hansen Jim Hatfield John Hatfield Zachary Hill Fritz Hirst Renze Hoeksema Jessica Hogle Bobby Hollis John Houston John Kellum, Jr. Greg Kern Max Kuniansky Starla Lacy Gary Lavey Melissa Lavinson Michael Lewis Ann Loomis Jeffrey Lyash Beverly Marshall Tammy McLeod Andy McNeil Kenneth Mercado Naveed Mughal Lee Nickloy Jeanette Pablo Paulette Pidcock Amy Plaster Michael Poling Scott Prochazka Company NV Energy Entergy Wisconsin Energy Corp Arizona Public Service Company Arizona Public Service Company Pinnacle West Capital Corporation Arizona Public Service Company Alliant Energy Corp. TECO Energy Corp. DTE Energy Pacific Gas & Electric Company NV Energy CenterPoint Energy CenterPoint Energy NV Energy NV Energy NV Energy NV Energy Pacific Gas & Electric Company Duke Energy Dominion Duke Energy Duke Energy Arizona Public Service Company NV Energy CenterPoint Energy NV Energy Pinnacle West Capital Corporation PNM Resources PPL Corporation CMS Energy Kansas City Power & Light Company CenterPoint Energy 8 2012 Individual Contributions The following participants have given personal contributions up to $1,000 to PowerPAC since January 1, 2012 Name Bob Rowe Dilek Samil Tony Sanchez Mark Schiavoni Rebecca Sczudlo Michael Sewell Mark Shank Toby Short Mary Simmons John Slanina Robert Stewart Rob Stillwell Judy Stokey Lori Sundberg Mario Villar Jeanne Wolak Lloyd Yates Company Northwestern Energy NV Energy NV Energy Arizona Public Service Company NiSource Inc. Duke Energy NV Energy Duke Energy NV Energy CenterPoint Energy NV Energy NV Energy NV Energy Arizona Public Service Company NV Energy Southern Company Duke Energy 9 2012 Individual Contributions The following EEI employees have given personal contributions or commitments to PowerPAC since January 1, 2012 Name Scott Aaronson Eric Ackerman Mark Agnew Sarah Ball Karen Bernard Eric Blume Richard Bozek David Bridges Bruce Brown Wanda Campbell Daniel Chartier Ed Comer Maurie Dugger John Easton Chris Eisenbrey Jim Fama Bill Fang Emily Fisher Miranda Gregory Isetta Harmon Matt Hastings Chris Hickling Barbara Hindin Jeanny Ho Eric Holdsworth Meg Hunt Tony Ingram Lou Jahn Steve Kiesner John Kinsman Tom Kuhn Name Sarah Lashford Rick Loughery Brian McCormack Jennifer McKinney Richard McMahon Wally Mealiea Mary Miller Jonathan Myers Sarah Novascone Gregory Obenchain Cal Odom Richard O'Grady Terri Oliva Jim Owen David Owens Mark Planning Jim Roewer Steve Rosenstock John Schlenker Bill Serelis Quin Shea Louise Smoak Kathy Steckelberg Rick Tempchin Sam Tornabene Brad Viator Keith Voight Stephanie Voyda Karla Whiting Brian Wolff Lisa Wood 10 PAC-to-PowerPAC Contributor List PAC-to-PAC contributions received since January 1, 2012 PAC AEP Committee for Responsible Government ALLETE PAC Alliant Energy Employees PAC Ameren Fed PAC CenterPoint Energy CMS Energy Employees for Better Government Dominion PAC DTE Energy Company PAC Edison International PAC Energy Future Holdings PAC ENPAC Federal – Entergy Exelon PAC FirstEnergy PAC IDA-PAC of Idaho Power KCPL Power PAC MDU Resources Group Good Government Fun National Grid USA PAC NextEra Energy PAC NiSource, Inc. PAC Northeast Utilities Employees PAC OGE Energy Corporation Employees’ PAC PSEG PAC PG&E Corporation Energy PAC PHI PAC Pinnacle West PAC PNM Responsible Citizens Group PPL People for Good Government Progress Energy Employees' Federal PAC Puget Sound Energy PAC for Good Government Southern Company Employees PAC TEPAC Vectren PAC WEPAC Xcel Energy Employee PAC 11 Contribution $5,000 $1,000 $1,000 $5,000 $2,500 $5,000 $5,000 $5,000 $5,000 $5,000 $5,000 $5,000 $5,000 $1,000 $2,000 $1,000 $3,500 $5,000 $2,000 $3,500 $5,000 $2,000 $5,000 $5,000 $5,000 $5,000 $5,000 $5,000 $500 $5,000 $3,000 $2,500 $1,000 $5,000 2011-2012 Disbursements NAME COMMITTEE NAME PARTY TYPE AMOUNT Terri Sewell Terri Sewell for Congress Democrat Re-elect $1,000 Lisa Murkowski Lisa Murkowski Mark Begich Mark Begich Denali PAC Lisa Murkowski for US Senate Alaskans for Begich 2014 Great Land PAC Republican Republican Democrat Democrat Leadership Re-elect Re-elect Leadership $3,000 $2,500 $5,000 $2,500 Jeff Flake Paul Gosar Ed Pastor Matt Salmon Jeff Flake for U.S. Senate, Inc. Paul Gosar for Congress Pastor for Arizona Matt Salmon for Congress Republican Republican Democrat Republican Elect Re-elect Re-elect Elect $2,500 $1,000 $1,000 $1,000 Mark Pryor Tim Griffin Mark Pryor for US Senate Tim Griffin for Congress Democrat Republican Re-elect Re-elect $2,000 $1,000 Dianne Feinstein Jackie Speier Mary Bono Mack Kevin McCarthy Kevin McCarthy Brian Bilbray Devin Nunes Mike Thompson Jim Costa Joe Baca Tony Cardenas Feinstein for Senate Jackie Speier for Congress Mary Bono Mack Committee Kevin McCarthy for Congress Majority Committee PAC Brian Bilbray for Congress Devin Nunes for Congress Mike Thompson for Congress Jim Costa for Congress Friends of Joe Baca Tony Cardenas for Congress Democrat Democrat Republican Republican Republican Republican Republican Democrat Democrat Democrat Democrat Re-elect Re-elect Re-elect Re-elect Leadership Re-elect Re-elect Re-elect Re-elect Re-elect Re-elect $5,000 $1,000 $3,500 $5,000 $10,000 $1,000 $1,000 $3,000 $3,500 $1,000 $1,000 Mark Udall Mark Udall Michael Bennet Diana DeGette Ed Perlmutter Cory Gardner Udall for Colorado Peak PAC Bennet for Colorado Diana Degette for Congress Ed Perlmutter for Congress Gardner for Congress Democrat Democrat Democrat Democrat Democrat Republican Re-elect Leadership Re-elect Re-elect Re-elect Re-elect $1,000 $5,000 $1,000 $1,000 $1,000 $1,000 Chris Murphy Jim Himes John Larson Friends of Chris Murphy Jim Himes for Congress Larson for Congress Democrat Democrat Democrat Elect Re-elect Re-elect $3,500 $2,000 $1,000 Alabama Congresswoman Alaska Senator Senator Senator Senator Arizona Senate Candidate Congressman Congressman Congressional Candidate Arkansas Senator Congressman California Senator Congresswoman Congresswoman Congressman Congressman Congressman Congressman Congressman Congressman Congressman Congressional Candidate Colorado Senator Senator Senator Congresswoman Congressman Congressman Connecticut Senate Candidate Congressman Congressman 12 Delaware Senator Chris Coons Chris Coons for Delaware Democrat Re-elect $2,500 Marco Rubio Marco Rubio Bill Nelson Connie Mack John Mica Marco Rubio for US Senate Reclaim America PAC Bill Nelson for US Senate Friends of Connie Mack Mica for Congress Republican Republican Democrat Republican Republican Re-elect Leadership Re-elect Re-elect Re-elect $2,500 $2,500 $2,000 $1,000 $1,000 Wasserman-Schultz for Congress Democrat Re-elect $2,500 Gingrey for Congress Friends of John Barrow DAWG PAC Sanford D. Bishop, Jr. For Congress Republican Democrat Democrat Re-elect Re-elect Leadership $1,000 $2,000 $2,500 Democrat Re-elect $1,000 Linda Lingle Senate Committee Republican Elect $1,000 Florida Senator Senator Senator Congressman Congressman Congresswoman Debbie Wasserman-Schultz Georgia Congressman Phil Gingrey Congressman John Barrow Congressman John Barrow Congressman Sanford D. Bishop, Jr Hawaii Senate Candidate Linda Lingle Idaho Senator Congressman Congressman Jim Risch Mike Simpson Raul Labrador Jim Risch for US Senate Simpson for Congress Raul Labrador for Idaho Republican Republican Republican Re-elect Re-elect Re-elect $1,500 $3,000 $1,000 Congressman Congressman Congressman Congressman Congressman Congressman Congresswom an Congressman Adam Kinzinger John Shimkus John Shimkus Peter Roskam Aaron Schock Randy Hultgren Kinzinger for Congress Volunteers for Shimkus John S Fund Roskam for Congress Schock for Congress Randy Hultgren for Congress Republican Republican Republican Republican Republican Republican Re-elect Re-elect Re-elect Re-elect Re-elect Re-elect $2,000 $4,000 $2,500 $5,500 $1,000 $1,000 Judy Biggert Bobby Rush Judy Biggert for Congress Citizens for Rush Republican Democrat Re-elect Re-elect $2,000 $4,500 Senator Congressman Richard Lugar Peter Visclosky Friends of Dick Lugar Visclosky for Congress Republican Democrat Re-elect Re-elect $3,500 $2,000 Senator Congressman Tom Harkin Tom Latham Citizens for Harkin Latham for Congress Democrat Republican Re-elect Re-elect $1,000 $3,500 Pompeo for Congress Inc. Lynn Jenkins for Congress Republican Republican Re-elect Re-elect $1,000 $1,000 Illinois Indiana Iowa Kansas Congressman Mike Pompeo Congresswoman Lynn Jenkins 13 Kentucky Senator Congressman Congressman Congressman Mitch McConnell Ed Whitfield Ed Whitfield Ben Chandler McConnell Senate Committee Whitfield for Congress Thoroughbred PAC Ben Chandler for Congress Republican Republican Republican Democrat Re-elect Re-elect Leadership Re-elect $2,500 $7,000 $5,000 $1,000 Senator Congressman Congressman Congressman Congressman Congressman Congressman Mary Landrieu Cedric Richmond Steve Scalise Steve Scalise Charles Boustany Rodney Alexander Bill Cassidy Friends of Mary Landrieu, Inc. Richmond for Congress Scalise for Congress Eye of the Tiger PAC Boustany for Congress Rodney Alexander for Congress Bill Cassidy for Congress Democrat Democrat Republican Republican Republican Republican Republican Re-elect Re-elect Re-elect Leadership Re-elect Re-elect Re-elect $3,500 $500 $4,500 $5,000 $1,000 $1,000 $1,000 Senator Congressman Olympia Snowe Mike Michaud Snowe for Senate Michaud for Congress Republican Democrat Re-elect Re-elect $1,000 $1,000 Senator Congressman Congressman Congressman Ben Cardin Steny Hoyer Steny Hoyer Chris Van Hollen Cardin for Senate Ameripac Hoyer for Congress Van Hollen for Congress Democrat Democrat Democrat Democrat Re-elect Leadership Re-elect Re-elect Scott Brown Scott Brown for Senate Republican Re-elect Senator Congressman Congressman Congressman Congressman Congressman Congressman Congressman Congressman Debbie Stabenow Dave Camp Dave Camp Mike Rogers Mike Rogers Fred Upton Fred Upton John Dingell Sandy Levin Stabenow for US Senate Dave Camp for Congress Continuing the Majority Party PAC Rogers for Congress MIKE R Fund Upton for All of Us TRUST PAC John D. 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PAC Friends of Max Baucus Montanans for Tester Democrat Democrat Democrat Leadership Re-elect Re-elect Senator Congressman Ben Nelson Lee Terry Nelson 2012 Lee Terry for Congress Democrat Republican Re-elect Re-elect $1,000 $3,000 Heller for Senate Amodei for Congress Friends of Joe Heck Republican Republican Republican Re-elect Re-elect Re-elect $3,000 $1,000 $1,000 Friends of Kelly Ayotte Bass Victory Committee Republican Republican Re-elect Re-elect $1,000 $3,000 Menendez for Senate Frelinghuysen for Congress Scott Garrett for Congress Jon Runyan for Congress Lance for Congress Hochul for Congress Democrat Republican Republican Republican Republican Democrat Re-elect Re-elect Re-elect Re-elect Re-elect Re-elect $2,000 $3,000 $2,500 $2,000 $1,000 $1,000 Heather Wilson for Senate Republican Elect $4,000 Ben Lujan People for Ben Democrat Re-elect $2,500 Kirsten Gillibrand Joe Crowley Ed Towns Steve Israel Bill Owens Paul Tonko Michael Grimm Chris Gibson Tom Reed Nan Hayworth Kathy 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Menendez Congressman Rodney Frelinghuysen Congressman Scott Garrett Congressman Jon Runyan Congressman Leonard Lance Congresswoman Kathy Hochul New Mexico Senate Candidate Heather Wilson Congressman New York Senator Congressman Congressman Congressman Congressman Congressman Congressman Congressman Congressman Congresswoman Congresswoman North Carolina Senator Congresswoman Congressman Congressman 15 Congressman Mike McIntyre Mike McIntyre for Congress ___________ Democrat _____ Re-elect ________ $2,000 ____ Senator Congressman Congressman Congressman Congressman Congressman Congressman Congressman Congressman Rob Portman John Boehner John Boehner Steve Stivers Patrick Tiberi Patrick Tiberi Bill Johnson Tim Ryan Bob Latta Portman for Senate Committee The Freedom Project Friends of John Boehner Stivers for Congress Tiberi for Congress Pioneer PAC Bill Johnson for Congress Tim Ryan for Congress Latta for Congress Republican Republican Republican Republican Republican Republican 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Friends of Jim Clyburn BRIDGE PAC Republican Democrat Democrat Re-elect Re-elect Re-elect $2,500 $10,000 $10,000 North Dakota Ohio Oklahoma Oregon Pennsylvania Senator Bob Casey Congressman Mike Doyle Congressman Tim Holden Congressman Charlie Dent Congressman Jason Altmire Congressman Jim Gerlach Congressman Jim Gerlach Congressman Tim Murphy Congressman Pat Meehan Congressman Joe Pitts Congresswoman Allyson Schwartz Congressman Chaka Fattah Congressman Mark Critz Rhode Island Senator Sheldon Whitehouse South Carolina Senator Lindsey Graham Congressman James Clyburn Congressman James Clyburn 16 South Dakota Senator Congresswoma n Tim Johnson Tim Johnson for South Dakota Democrat Re-elect $3,500 Kristi Noem Kristi for Congress Republican Re-elect $1,000 Bob Corker for Senate 2012 Marsha Blackburn for Congress Cooper for Congress Republican Republican Democrat Re-elect Re-elect Re-elect $5,500 $1,000 $1,000 John Cornyn David Dewhurst Pete Sessions John Culberson Joe Barton Joe Barton Pete Olson Ralph Hall Michael Burgess Mac Thornberry Michael Williams Silvestre Reyes Texans for Senator John Cornyn Dewhurst for Texas Pete Sessions for Congress Culberson for Congress Congressman Joe Barton Texas Freedom Fund Olson for Congress Committee Hall for Congress Committee Michael Burgess for Congress Thornberry for Congress Michael Williams for Congress The Reyes Committee Republican Republican Republican Republican Republican Republican Republican Republican Republican Republican Republican Democrat Re-elect Re-elect Re-elect Re-elect Re-elect Leadership Re-elect Re-elect Re-elect Re-elect Elect Re-elect $1,000 $1,000 $1,500 $1,000 $5,000 $2,500 $2,000 $1,000 $3,000 $1,000 $1,000 $1,000 Congressman Gene Green Gene Green Congressional Campaign Democrat Re-elect $1,000 Congressman Henry Cuellar Texans for Henry Cuellar Democrat Re-elect $1,000 Senator Congressman Orrin Hatch Jim Matheson Hatch Election Committee Matheson for Congress Republican Democrat Re-elect Re-elect $6,000 $2,000 Senator Congressman Congressman Congressman Mark Warner Eric Cantor Morgan Griffith Robert Hurt Friends of Mark Warner ERICPAC Morgan Griffith for Congress Robert Hurt for Congress Democrat Republican Republican Republican Re-elect Leadership Re-elect Re-elect Congressman Congressman Rick Larsen Doc Hastings Citizens to Elect Rick Larsen Friends of Doc Hastings Democrat Republican Re-elect Re-elect $2,000 $1,000 Senator Congressman Congressman Joe Manchin Nick Rahall David McKinley Manchin for West Virginia Keep Nick Rahall in Congress McKinley for Congress Democrat Democrat Republican Re-elect Re-elect Re-elect $3,500 $1,000 $2,000 Shelley Moore Capito for Congress Republican Re-elect $1,000 Tennessee Senator Bob Corker Congresswoman Marsha Blackburn Congressman Jim Cooper Texas Senator Senate Candidate Congressman Congressman Congressman Congressman Congressman Congressman Congressman Congressman Congressional Candidate Congressman Utah Virginia $2,500 $10,000 $1,000 $1,000 Washington West Virginia Congresswoman Shelley Moore Capito 17 Wisconsin Congressman Congressman Ron Kind Paul Ryan Kind for Congress Committee Ryan for Congress Democrat Republican Re-elect Senator John Barrasso Friends of John Barrasso Republican Senator John Barrasso Our Common Values PAC Republican Congresswoman Cynthia Lummis Lummis for Congress Republican Presidential Presidential Candidate Mitt Romney Romney for President, Inc. Republican Presidential Candidate Mitt Romney Romney Victory Committee Republican Caucus Leadership PACs Blue Dog PAC Democrat Moderate Democrats PAC Democrat New Democrat Coalition PAC Democrat Value in Electing Women PAC Republican Tuesday Group PAC Republican Republican Mainstreet Partnership PAC Republican Congressional Black Caucus Democrat Committees Democratic Congressional Campaign Committee Democrat Democratic Senatorial Campaign Committee Democrat National Republican Senatorial Committee Republican National Republican Congressional Committee Republican Republican National Committee Republican Percentage of disbursements to Democrats*: 40.0% Percentage of disbursements to Republicans*: 60.0% *Includes House and Senate members Total Senators: 42 Total House of Representatives: 129 Re-elect Re-elect $2,000 $4,000 Wyoming 18 Re-elect $9,000 $1,000 $1,000 Elect Elect $5,000 $5,000 Leadership Leadership PAC Leadership PAC Leadership PAC Leadership PAC Leadership PAC Leadership PAC Leadership PAC Committee Committee Committee Committee Committee $10,000 $5,000 $10,000 $2,500 $5,000 $10,000 $2,500 $30,000 $30,000 $30,000 $30,000 $30,000 Authorization for Solicitation Form Name/Title_________________________________________________________________________________ Company___________________________________________________________________________________ p Y ES, I want to be an active participant in PowerPAC to help build political POWER for the electric utility industry. I authorize PowerPAC to solicit me as an executive of my corporation, which is a member of the Edison Electric Institute. This permission to solicit has not and will not be granted to any other trade association during this or any other calendar year indicated below. p P owerPAC may also contact my designated Washington Representative regarding PowerPAC. Designated Washington Rep p Y ES, PowerPAC may solicit all of the executives in my company. I understand that EEI will not directly solicit executives of my company without contacting me first for guidance. p Y ES, PowerPAC may solicit the following executives in my company. I understand that EEI will not directly solicit executives of my company without contacting me first for guidance. ________________________________________________________________________________________ ________________________________________________________________________________________ ________________________________________________________________________________________ p I have already signed an Authorization to Solicit form for another trade association. Please contact our subsidiary company for authorization. Subsidiary Company Contact________________________________________________________________ Please note that Federal Election Commission regulations allow an executive of a subsidiary company that is a member of the Edison Electric Institute to sign an Authorization for Solicitation Form if the parent company has already signed for another trade association. Authorized for 2012 Authorized for 2014 Signature:____________________________________ Signature:____________________________________ Date: __/___/2012 Date: __/___/2014 Authorized for 2013 Authorized for 2015 Signature:____________________________________ Signature:____________________________________ Date: __/___/2013 Date: __/___/2015 Please complete, sign and fax to: PowerPAC of the Edison Electric Institute /FAX # (202) 508-5403 For questions or assistance, please call Maurie Dugger at (202) 508-5586 Paid for by PowerPAC of the Edison Electric Institute. Contributions to PowerPAC cannot be deducted as a charitable contribution for federal tax purposes. Federal law requires us to use our best efforts to collect and report the name, mailing address, occupation and the name of the employer of individuals whose contributions exceed $200 per calendar year. Contributions to PowerPAC are for political purposes only. 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UPCOMING MEETINGS September 2012 2012 2013 2014 2015 June 3-6 Annual Convention & Board Mtg.: JW Marriott Grande Lakes, Orlando, FL *September 12-14 Board & Chief Executive Meetings: The Broadmoor, Colorado Springs, CO November 11-14 Financial Conference: JW Marriott Desert Ridge Resort & Spa, Phoenix, AZ January 8-10 Board & Chief Executive Meetings: Arizona Biltmore, Phoenix, AZ March 19-21 Board & Chief Executive Meetings: Mandarin Oriental, Washington, DC June 9-12 Annual Convention & Board Mtg.: San Francisco Marriott Marquis, San Francisco, CA **September 10-12 Board & Chief Executive Meetings: The Broadmoor, Colorado Springs, CO November 10-13 Financial Conference: Orlando World Marriott Resort, Orlando, FL January 7-9 Board & Chief Executive Meetings: Arizona Biltmore, Phoenix, AZ March 4-6 Board & Chief Executive Meetings: Mandarin Oriental, Washington, DC June 8-11 Annual Convention & Board Mtg.: ARIA Resort & Casino, Las Vegas, NV September 2-4 Board & Chief Executive Meetings: The Broadmoor, Colorado Springs, CO September 8-10 Board & Chief Executive Meetings: The Broadmoor, Colorado Springs, CO *Date change due to National Political Conventions. Meeting pattern is Wednesday-Friday. **Date change