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26–883 2018

POWERING AMERICA: EXAMINING THE STATE OF 

THE ELECTRIC INDUSTRY THROUGH MARKET 

PARTICIPANT PERSPECTIVES 

HEARING 

BEFORE THE

SUBCOMMITTEE ON ENERGY 

OF THE

COMMITTEE ON ENERGY AND 

COMMERCE 

HOUSE OF REPRESENTATIVES 

ONE HUNDRED FIFTEENTH CONGRESS 

FIRST SESSION 

JULY 18, 2017 

Serial No. 115–45 

( 

Printed for the use of the Committee on Energy and Commerce 

energycommerce.house.gov 

(II) 

COMMITTEE ON ENERGY AND COMMERCE 

GREG WALDEN, Oregon 

Chairman 

JOE BARTON, Texas 

Vice Chairman 

FRED UPTON, Michigan 

JOHN SHIMKUS, Illinois 

TIM MURPHY, Pennsylvania 

MICHAEL C. BURGESS, Texas 

MARSHA BLACKBURN, Tennessee 

STEVE SCALISE, Louisiana 

ROBERT E. LATTA, Ohio 

CATHY MCMORRIS RODGERS, Washington 

GREGG HARPER, Mississippi 

LEONARD LANCE, New Jersey 

BRETT GUTHRIE, Kentucky 

PETE OLSON, Texas 

DAVID B. MCKINLEY, West Virginia 

ADAM KINZINGER, Illinois 

H. MORGAN GRIFFITH, Virginia 

GUS M. BILIRAKIS, Florida 

BILL JOHNSON, Ohio 

BILLY LONG, Missouri 

LARRY BUCSHON, Indiana 

BILL FLORES, Texas 

SUSAN W. BROOKS, Indiana 

MARKWAYNE MULLIN, Oklahoma 

RICHARD HUDSON, North Carolina 

CHRIS COLLINS, New York 

KEVIN CRAMER, North Dakota 

TIM WALBERG, Michigan 

MIMI WALTERS, California 

RYAN A. COSTELLO, Pennsylvania 

EARL L. ‘‘BUDDY’’ CARTER, Georgia 

FRANK PALLONE, JR., New Jersey 

Ranking Member 

BOBBY L. RUSH, Illinois 

ANNA G. ESHOO, California 

ELIOT L. ENGEL, New York 

GENE GREEN, Texas 

DIANA DEGETTE, Colorado 

MICHAEL F. DOYLE, Pennsylvania 

JANICE D. SCHAKOWSKY, Illinois 

G.K. BUTTERFIELD, North Carolina 

DORIS O. MATSUI, California 

KATHY CASTOR, Florida 

JOHN P. SARBANES, Maryland 

JERRY MCNERNEY, California 

PETER WELCH, Vermont 

BEN RAY LUJA ́ N, New Mexico 

PAUL TONKO, New York 

YVETTE D. CLARKE, New York 

DAVID LOEBSACK, Iowa 

KURT SCHRADER, Oregon 

JOSEPH P. KENNEDY, III, Massachusetts 

TONY CA ́ RDENAS, California 

RAUL RUIZ, California 

SCOTT H. PETERS, California 

DEBBIE DINGELL, Michigan 

(III) 

SUBCOMMITTEE ON ENERGY

FRED UPTON, Michigan 

Chairman 

PETE OLSON, Texas 

Vice Chairman 

JOE BARTON, Texas 

JOHN SHIMKUS, Illinois 

TIM MURPHY, Pennsylvania 

ROBERT E. LATTA, Ohio 

GREGG HARPER, Mississippi 

DAVID B. MCKINLEY, West Virginia 

ADAM KINZINGER, Illinois 

H. MORGAN GRIFFITH, Virginia 

BILL JOHNSON, Ohio 

BILLY LONG, Missouri 

LARRY BUCSHON, Indiana 

BILL FLORES, Texas 

MARKWAYNE MULLIN, Oklahoma 

RICHARD HUDSON, North Carolina 

KEVIN CRAMER, North Dakota 

TIM WALBERG, Michigan 

GREG WALDEN, Oregon (ex officio) 

BOBBY L. RUSH, Illinois 

Ranking Member 

JERRY MCNERNEY, California 

SCOTT H. PETERS, California 

GENE GREEN, Texas 

MICHAEL F. DOYLE, Pennsylvania 

KATHY CASTOR, Florida 

JOHN P. SARBANES, Maryland 

PETER WELCH, Vermont 

PAUL TONKO, New York 

DAVID LOEBSACK, Iowa 

KURT SCHRADER, Oregon 

JOSEPH P. KENNEDY, III, Massachusetts 

G.K. BUTTERFIELD, North Carolina 

FRANK PALLONE, JR., New Jersey (ex 

officio) 

(V) 

C O N T E N T S 

Page 

Hon. Fred Upton, a Representative in Congress from the State of Michigan, 

opening statement ................................................................................................ 1 

Prepared statement .......................................................................................... 3 

Hon. Bobby L. Rush, a Representative in Congress from the State of Illinois, 

opening statement ................................................................................................ 4 

Hon. Greg Walden, a Representative in Congress from the State of Oregon, 

opening statement ................................................................................................ 5 

Prepared statement .......................................................................................... 6 

Hon. Frank Pallone, Jr., a Representative in Congress from the State of 

New Jersey, opening statement .......................................................................... 7 

Prepared statement .......................................................................................... 8 

WITNESSES

Joseph T. Kelliher, Executive Vice President, Federal Regulatory Affairs, 

NextEra Energy, Inc. ........................................................................................... 9 

Prepared statement .......................................................................................... 12 

Answers to submitted questions ...................................................................... 122 

Lisa G. McAlister, Senior Vice President and General Counsel For Regulatory 

Affairs, American Municipal Power, Inc. ........................................................... 20 

Prepared statement .......................................................................................... 22 

Answers to submitted questions ...................................................................... 124 

Steven Schleimer, Senior Vice President of Government & Regulatory Affairs, 

Calpine .................................................................................................................. 43 

Prepared statement .......................................................................................... 45 

Answers to submitted questions ...................................................................... 133 

Jackson Reasor, Chief Executive Officer, Old Dominion Electric Cooperative ... 54 

Prepared statement .......................................................................................... 56 

Answers to submitted questions ...................................................................... 135 

Tamara Linde, Executive Vice President and General Counsel, Public Service 

Enterprise Group, Inc. ......................................................................................... 66 

Prepared statement .......................................................................................... 68 

Answers to submitted questions ...................................................................... 143 

Kenneth D. Schisler, Vice President of Regulatory and Government Affairs, 

EnerNOC .............................................................................................................. 77 

Prepared statement .......................................................................................... 79 

Answers to submitted questions ...................................................................... 146 

Alex Glenn, Senior Vice President of State and Federal Regulatory Legal 

Support, Duke Energy Corporation .................................................................... 83 

Prepared statement .......................................................................................... 85 

Answers to submitted questions ...................................................................... 150 

(1) 

POWERING AMERICA: EXAMINING THE STATE 

OF THE ELECTRIC INDUSTRY THROUGH 

MARKET PARTICIPANT PERSPECTIVES 

TUESDAY, JULY 18, 2017 

HOUSE OF REPRESENTATIVES, 

SUBCOMMITTEE ON ENERGY, 

COMMITTEE ON ENERGY AND COMMERCE, 

Washington, DC. 

The subcommittee met, pursuant to call, at 10:00 a.m., in room 

2123 Rayburn House Office Building, Hon. Fred Upton (chairman 

of the subcommittee) presiding. 

Present: Representatives Upton, Olson, Barton, Shimkus, Murphy, Latta, McKinley, Kinzinger, Griffith, Johnson, Long, Bucshon, 

Flores, Mullin, Hudson, Cramer, Walberg, Walden (ex officio), 

Rush, McNerney, Peters, Green, Castor, Sarbanes, Tonko, 

Loebsack, Schrader, Kennedy, Butterfield, and Pallone (ex officio). 

Staff present: Elena Brennan, Legislative Clerk, Energy/Environment; Adam Buckalew, Professional Staff Member, Health; Karen 

Christian, General Counsel; Kelly Collins, Staff Assistant; Wyatt 

Ellertson, Research Associate, Energy/Environment; Adam Fromm, 

Director of Outreach and Coalitions; Tom Hassenboehler, Chief 

Counsel, Energy/Environment; A.T. Johnston, Senior Policy Advisor, Energy; Alex Miller, Video Production Aide and Press Assistant; Mark Ratner, Policy Coordinator; Annelise Rickert, Counsel, 

Energy; Dan Schneider, Press Secretary; Sam Spector, Policy Coordinator, Oversight and Investigations; Jason Stanek, Senior Counsel, Energy; Madeline Vey, Policy Coordinator, Digital Commerce 

and Consumer Protection; Priscilla Barbour, Minority Energy Fellow; Jeff Carroll, Minority Staff Director; David Cwiertny, Minority 

Energy/Environment Fellow; Rick Kessler, Minority Senior Advisor 

and Staff Director, Energy and Environment; Alexander Ratner, 

Minority Policy Analyst; and Tuley Wright, Minority Energy and 

Environment Policy Advisor. 

OPENING STATEMENT OF HON. FRED UPTON, A REPRESENTATIVE IN CONGRESS FROM THE STATE OF MICHIGAN 

Mr. UPTON. It is my understanding that Mr. Rush is coming in 

the door, so we will now come to order at the subcommittee and 

the chair will recognize himself for an opening statement. 

So I am certainly pleased to be here today to kick off this first 

of many hearings focused on America’s electricity system. And as 

many in this room are aware, this committee has had an extensive 

history overseeing the nation’s power sector. In fact, the namesake 

2 

of this very building, Speaker Rayburn, worked as the chairman of 

the Energy and Commerce Committee to pass the Federal Power 

Act back in 1935, a law which continues to serve as the legal foundation of America’s electricity system. 

More recently, the committee was instrumental in the discussion 

and actions resulting in the creation of organized wholesale electricity markets and other power market reforms ensuring that 

rates continue to be just and reasonable. I can confidently say that 

this committee’s efforts to oversee the nation’s power sector must 

remain ongoing, as the ever-changing nature of the U.S. electricity 

system guarantees that there will always be new challenges to 

solve and new opportunities to seize. 

With that in mind, I am excited to launch a new set of Energy 

and Commerce hearings today entitled Powering America series. 

This series of hearings is going to take a comprehensive look at recent developments and challenges in the way that we generate, 

transmit, and consume electricity in the U.S. and today’s hearing 

will give us the opportunity to examine the state of the electric industry through the perspective of various market participants. 

After hearing from each of these marketing participants this 

morning, we are going to be holding a second Powering America series hearing next week where we are going to be receiving testimony from each of the RTOs and ISOs who are responsible for operating America’s regional wholesale electricity markets. It should 

also be said that in the coming months we are going to be announcing additional hearings in this series which will focus on more indepth topics and issues related to the U.S. electricity system. 

Joining us in today’s discussion we have a full range of experts 

representing a wide range of stakeholders from across the electric 

sector and I would like to welcome them and thank them for being 

here. 

As I am sure that each of our witnesses will attest to, the nation’s electricity industry and system is undergoing a significant 

period of transformation. This transformation is affecting the composition of the country’s electricity generation mix, the way that industry and regulators are approaching grid reliability, and how federal energy policies are interacting with state policies. Many of the 

recent developments and changes within the electricity sector are 

creating tremendous benefits for American consumers. 

U.S. electricity prices are low, employment within the energy sector continues to rise, and advanced technologies are giving consumers more control over how they interact with the grid. And it 

is safe to say that the American electricity industry is a world leader and deserves more credit for the amazing work that they do. 

With that being said, I know that the U.S. electricity system is 

not perfect nor will it ever be. The electricity industry is facing dynamic challenges in an uncertain future. The witnesses before us 

today have serious ideas on how electricity markets and energy 

policies can be improved, and this committee welcomes those ideas 

and is eager to engage in a meaningful discussion as to how we can 

strengthen the grid and how to provide greater value to consumers. 

No one here is under the illusion that these issues will be understood and addressed in one or two hearings. The U.S. electricity 

system is the largest, most complex collection of machines and comVerDate Nov 24 2008 15:59 Feb 12, 2018 Jkt 037690 PO 00000 Frm 00008 Fmt 6633 Sfmt 6633 I:\MY DOCS\HEARINGS 115\HEARINGS\115-45 CHRIS
3 

puters in the world and are influenced by a staggering number of 

stakeholders. 

These electricity systems issue are complicated and in order to 

address them it will require an extended effort by this committee 

and by the Congress. Moreover, tackling these issues will require 

a bipartisan effort, which is why we have worked with our colleagues on both sides of the aisle in planning and conducting this 

hearing. 

Reliable, affordable, clean energy is a vital component of every 

American’s life. Going forward, we have got to strive to enhance 

the generation, delivery, and marketing of electricity in a way that 

continues to enrich the lives of all. And with that in mind, I look 

forward to the hearing and future hearings and would yield 5 minutes to the ranking member of the subcommittee, my friend from 

Illinois, Mr. Rush. 

[The opening statement of Mr. Upton follows:] 

PREPARED STATEMENT OF HON. FRED UPTON

Good morning. I am pleased to be here today to kick off this first of many hearings focused on America’s electricity system. As many in this room are aware, this 

Committee has an extensive history overseeing the nation’s power sector. In fact, 

the namesake of this very building, Speaker Sam Rayburn, worked as the Chairman 

of the Energy and Commerce Committee to pass the Federal Power Act in 1935, a 

law which continues to serve as the legal foundation of America’s Electricity System. 

More recently, this Committee was instrumental in the discussion and actions resulting in the creation of organized wholesale electricity markets and other power 

marketing reforms, ensuring that rates continue to be ‘‘just and reasonable’’. I can 

confidently say, that this Committee’s efforts to oversee the nation’s power sector 

must remain ongoing as the ever-changing nature of the U.S. electricity system 

guarantees that there will always be new challenges to solve and new opportunities 

to seize. 

With that in mind, I am excited to launch a new set of Energy and Commerce 

Committee hearings today, titled the ‘‘Powering America Series’’. This series of 

hearings will take a comprehensive look at recent developments and challenges in 

the way we generate, transmit, and consume electricity in the United States. Today’s hearing will give us the opportunity to examine the state of the electric industry through the perspective of various market participants. After hearing from each 

of these market participants this morning, we will be holding a second ‘‘Powering 

America Series’’ hearing next week, where we will be receiving testimony from each 

of the RTOs and ISOs who are responsible for operating America’s regional wholesale electricity markets. It should also be said that in the coming months, we will 

be announcing additional hearings in this series which will focus on more in-depth 

topics and issues related to the U.S. electricity system. 

Joining us in today’s discussion, we have a full panel of experts representing a 

wide range of stakeholders from across the electric sector and I would like to welcome them and thank them for being here. As I am sure each of our witnesses will 

attest to, the nation’s electricity industry and system is undergoing a significant period of transformation. This transformation is affecting the composition of the country’s electricity generation mix, the way industry and regulators are approaching 

grid reliability, and how Federal energy policies are interacting with State policies. 

Many of the recent developments and changes within the electricity sector are creating tremendous benefits for American consumers. U.S. electricity prices are low; 

employment within the energy sector continues to rise; and advanced technologies 

are giving consumers more control over how they interact with the grid. It is safe 

to say that the American electricity industry is a world leader and deserves more 

credit for the amazing work they do. 

With that being said, I know that the U.S. electricity system is not perfect, nor 

will it ever be. The electricity industry is facing dynamic challenges and an uncertain future. The witnesses before us today have serious ideas on how electricity 

markets and energy policies can be improved. This Committee welcomes these ideas 

and is eager to engage in a meaningful discussion on how to strengthen the grid 

and how to provide greater value to American consumers. 

4 

No one here is under the illusion that these issues will be understood and addressed in one or two hearings. The U.S. electricity system is the largest, most-complex collection of machines and computers in the world and is influenced by a staggering number of stakeholders. These electricity system issues are complicated and 

in order to address them it will require an extended effort by this Committee, and 

by this Congress. Moreover, tackling these issues will require a bipartisan effort. 

Which is why we have worked with our colleagues on the other side of the aisle in 

planning and conducting this hearing. 

Reliable, affordable, clean electricity is a vital component of every American’s life. 

Going forward, we must strive to enhance the generation, delivery, and marketing 

of electricity in a way that continues to enrich the lives of all Americans. With this 

goal in mind, I look forward to this hearing and future hearings to come in this series. 

OPENING STATEMENT OF HON. BOBBY L. RUSH, A REPRESENTATIVE IN CONGRESS FROM THE STATE OF ILLINOIS 

Mr. RUSH. I want to thank you, Mr. Chairman. Mr. Chairman, 

this hearing is important because it is examining the state of the 

electric industry through market participant perspectives. 

Mr. Chairman, we know that the electricity grid of the 21st century will look significantly different than the grid of the last century, and rightfully so. Even as the Trump administration attempts 

to weaken federal environmental regulations and Congress fails to 

act in any meaningful way to address climate change, we see businesses, municipalities, states, and individual consumers step up 

their own campaigns to address this critical issue. 

As consumers become more aware of their carbon footprint and 

how their behavior impacts their environment, they are also more 

demanding in terms of information, they are more demanding in 

terms of control over how energy is produced and consumed. 

Indeed, Mr. Chairman, while many changes in our electric grid 

are spurred by state and federal policy and marketing forces, it is 

important to understand that consumers are also driving many of 

the trends we see taking place in the electricity market. From an 

increase in smart meters such as the ones being installed throughout my home city of Chicago to smarter appliances, consumers 

want the tools to more responsibly use energy both as a way to 

save money and as a way to save the environment. Other current 

trends include greater demand for cleaner, renewable sources of energy to compete with the traditional fossil fuels as well as increase 

in distributed generation and demand response resources. 

Mr. Chairman, the result of these trends, as a DOE draft report 

suggests, does not make the grid less reliable but rather the opposite. The DOE study indicates that having fuel diversity has in fact 

improved grid stability. I want to quote, Mr. Chairman, that very 

same report. ‘‘The power system is more reliable today due to better planning, market discipline, and better operating rules and 

standards,’’ is the remarks from that report. 

Mr. Chairman, with the federal government abdicating its responsibility in enacting comprehensive energy policy that addresses 

one of the world’s most pressing challenges, it is even more vital 

that we provide the resources and guidance for states to take more 

of a permanent role in advancing smart and sustainable energy 

policies. 

Congress should not stand in the way of states like my own, Illinois, Mr. Chairman, that choose to enact renewable energy portVerDate Nov 24 2008 15:59 Feb 12, 2018 Jkt 037690 PO 00000 Frm 00010 Fmt 6633 Sfmt 6633 I:\MY DOCS\HEARINGS 115\HEARINGS\115-45 CHRIS
5 

folios that provide credit to reliable zero or zero-carbon baseload 

sources of energy, including nuclear power, but rather Congress 

should ensure that FERC has the necessary mechanisms to meet 

the challenges and take advantage of the opportunities found in today’s electric grid. 

By almost all accounts, Mr. Chairman, for the foreseeable future, 

the nation’s energy mix will continue to include sources from all of 

the above portfolios including cleaner burning fossil fuels, nuclear, 

and renewables. So Mr. Chairman, we must make sure that regulators have the tools and have the authority that they need to effectively and efficiently manage this portfolio. 

So Mr. Chairman, I look forward to engaging today’s panel of distinguished industry insiders and hearing from them regarding the 

opportunities and the challenges that we face in terms of electric 

infrastructure. I want to thank you, Mr. Chairman. With that I 

yield back. 

Mr. UPTON. Thank you. The chair now recognizes the chair of the 

full committee, the gentleman from Oregon, Mr. Walden, for 5 minutes for an opening statement. 

OPENING STATEMENT OF HON. GREG WALDEN, A REPRESENTATIVE IN CONGRESS FROM THE STATE OF OREGON 

Mr. WALDEN. Thank you very much, Mr. Chairman. And welcome to all of our witnesses and guests today. Last fall, this subcommittee held a hearing where a distinguished panel of witnesses 

described the origins of the Federal Power Act and how it has withstood the test of time. That testimony provided us with an historical context of how the federal government regulates the electricity 

sector. 

Having explored those historical perspectives, today we begin examining the current state of the electricity industry. As we embark 

on the Powering America series of hearings, I would also like to 

welcome our witnesses again who are leaders representing a diverse set of utilities and market participants. We greatly value 

your input and counsel. 

American consumers have come to expect safe, reliable, and affordable supplies of power regardless of how they receive their electricity. My district in Oregon, we receive electricity from just about 

every source including renewables. We get coal, we get natural gas, 

we get hydro, we get solar, and we get wind. We also receive it 

from cooperatives and public utility districts and municipalities 

and IOUs. In fact, we have just about everything out there. 

In all these situations though, we expect to have power when we 

flip the switch and we expect to be at 60 cycles and 120 or 240 or 

whatever, but we expect it to work, and yet we know it is becoming 

more and more complex to provide that energy especially as we integrate and go up and down the grid. 

New market participants offering advanced technologies and innovative services are changing the face of the industry faster than 

many have expected and that pace of change will only increase over 

time. At the same time, wholesale electricity prices are at near 

record lows around the United States. 

While this is largely a result of cheap and plentiful natural gas 

supplies, the emergence of renewable resources are also affecting 

6 

the composition of power being generated as well as market-clearing prices. As a result, in regions with competitive markets that 

dispatch generation based solely on lowest cost, we are seeing that 

some traditional baseload units, such as nuclear and coal-fired 

plants, cannot compete because they are too expensive to operate 

within their markets, causing some plants to retire before the end 

of their useful life. 

While on its face low electricity prices are a boon for consumers 

and businesses, we are now hearing from some segments of the industry that the loss of nuclear and coal units from the generation 

fleet could have longer term impacts on grid reliability. While this 

is an issue that the DOE is examining in its baseload study, this 

is also an issue that this committee is exploring. Additionally, recent proposals by states to advance certain public policies in the organized electricity markets have added yet another layer of complexity to an already complicated system. 

So my hope is that there is a path forward to achieve these state 

policies while also maintaining the integrity of the wholesale markets. I recognize this is not an easy task. Next week, we will continue our examination of the electricity system with executives 

from the RTOs and the ISOs who operate the transmission systems, but today I am interested in hearing directly from market 

participants regarding their experiences working in the electric sector and their thoughts on areas of potential improvement. 

I would note that our panel includes representatives that participate in both the non-restructured markets as well as all seven organized markets. So, as Chairman Upton noted, today is just the 

first in our Powering America series of hearings examining this industry. 

So I look forward to learning more about the state of the vital 

industry and hearing your thoughts regarding what, if any, reforms 

could help to achieve greater efficiencies, reliability, and competition in the wholesale markets while also continuing to deliver value 

to customers. As I have said previously, at the end of the day, our 

goal is to serve the interests of consumers and I look forward to 

your ideas to further that mission. 

And I will say at the outset, we have another subcommittee hearing going on, on 340B hospital issues, so I have to pop up to that 

one as well, but with that I would yield the balance of my time to 

the chairman of the Environment Subcommittee, Mr. Shimkus. 

[The prepared statement of Mr. Walden follows:] 

PREPARED STATEMENT OF HON. GREG WALDEN

Last fall this subcommittee held a hearing where a distinguished panel of witnesses described the origins of the Federal Power Act and how it has withstood the 

test of time. That testimony provided us with a historical context of how the federal 

government regulates the electricity sector. Having explored those historical perspectives, today we will be examining the current state of the electricity industry. 

As we embark on this ‘‘Powering America’’ series of hearings, I’d like to welcome 

today’s witnesses who are leaders representing a diverse set of utilities and markets 

participants. 

American consumers have come to expect safe, reliable, and affordable supplies 

of power—regardless of how they receive their electricity. In my district, residents 

in central and eastern Oregon receive their electricity from small cooperatives, 

which are often the only provider in vast rural areas in Oregon. In other areas, like 

in southern Oregon or my hometown of Hood River, consumers rely on large invesVerDate Nov 24 2008 15:59 Feb 12, 2018 Jkt 037690 PO 00000 Frm 00012 Fmt 6633 Sfmt 6633 I:\MY DOCS\HEARINGS 115\HEARINGS\115-45 CHRIS
7 

tor-owned utilities to supply their electricity. In both situations, Americans now expect their power on demand. However, producing and delivering electricity from a 

power plant to our homes and businesses is becoming increasingly complex. New 

market participants offering advanced technologies and innovative services are 

changing the face of the industry faster than many have expected, and that pace 

of change will only increase with time. 

At the same time, wholesale electricity prices are at near record lows around the 

country. While this is largely a result of cheap and plentiful natural gas supplies, 

the emergence of renewable resources are also affecting the composition of the 

power being generated as well as the market clearing prices. As a result, in regions 

with competitive markets that dispatch generation based solely on lowest-cost, we 

are seeing that some traditional ‘‘baseload’’ units, such as nuclear and coalfired 

plants, cannot compete because they are too expensive to operate within their markets, causing some plants to retire before the end of their useful life. 

While on its face, low electricity prices are a boon for consumers and businesses, 

we are now hearing from some segments of the industry that the loss of nuclear 

and coal units from the generation fleet could have longer-term impacts on grid reliability. While this is an issue that the DOE is examining in its ‘‘Baseload Study,’’ 

this is also an issue that the committee will be exploring. 

Additionally, recent proposals by states to advance certain public policies in the 

organized electricity markets have added yet another layer of complexity to an already complicated system. My hope is that there is a path forward to achieve these 

state policies while also maintaining the integrity of the wholesale markets. I recognize that this is not an easy task. 

Next week, we will continue our examination of the electricity system with executives from the RTOs and ISOs who operate the transmission systems—but today I 

am interested in hearing directly from market participants regarding their experiences working in the electric sector and their thoughts on areas of potential improvements. I would note that our panel includes representatives that participate 

in both the non-restructured markets as well as all seven organized markets. 

As Chairman Upton noted, today is just the first in our ‘‘Powering America’’ series 

of hearings examining the electricity industry. I look forward to learning more about 

the current state of this vital industry and hearing your thoughts regarding what, 

if any, reforms could help to achieve greater efficiencies, reliability, and competition 

in the wholesale markets, while also continuing to deliver value to consumers. As 

I’ve said previously, at the end of the day, our goal is to serve the best interests 

of consumers and I look forward to your ideas to further that mission. 

Mr. SHIMKUS. Thank you, Mr. Chairman, and I will be brief. 

First of all, I want to welcome Joe for being on the panel, former 

committee staff. That shows you how old I am and how old you are 

starting to look there. 

Secondly, for my colleagues on both sides, we are soliciting cosponsors for our nuclear waste bill, the one we passed out of the 

full committee, 49–4. We are going to keep gathering names for the 

next 2 weeks, so check with your staff and make sure you get on 

that bill and I would appreciate it. 

With that, Mr. Chairman, I yield back. Oh, H.R. 3053 is the bill 

number. Thank you, Mr. Chairman. 

Mr. UPTON. As a co-sponsor of that bill I am glad to see that that 

is the case. And I would yield to the ranking member of the full 

committee, the gentleman from New Jersey, for an opening statement, Mr. Pallone. 

OPENING STATEMENT OF HON. FRANK PALLONE, JR., A REPRESENTATIVE IN CONGRESS FROM THE STATE OF NEW JERSEY 

Mr. PALLONE. Thank you, Mr. Chairman. And thanks for holding 

the hearing to provide us with a market participant perspective in 

our system of electricity regulation. Today’s hearing picks up on 

the issue that you started to focus on last Congress, Mr. Chairman, 

with our insightful hearing on the Federal Power Act. 

8 

Like that hearing, today’s hearing was developed in partnership 

between you and Chairman Walden and me and Ranking Member 

Rush, and this set up to be a completely non-partisan hearing with 

the goal of providing us important background for future decisions. 

I also want to welcome our witnesses, particularly Tammy Linde 

from New Jersey’s PSEG, and I would like to welcome back to the 

committee a former counsel to the subcommittee and FERC chair, 

Joe Kelliher. 

As I said previously, while our attention to electricity issues has 

been sporadic since the passage of the Energy Policy Act of 2005, 

there was a time when it seemed like this committee held hearings 

on the electric sector almost weekly. Now, developments in the 

electricity sector and the regional markets, both promising and concerning, require us to return again to a serious assessment of the 

state of the electric sector and how it is regulated. 

Technology has dramatically transformed the possibilities for 

cost effectively generating and efficiently delivering electric energy 

to homes, businesses, and manufacturing facilities from a variety 

of sources. Distributed generation both fossil- and renewable-based 

along with improving storage options, smart meters, microgrids, 

and other technologies, have altered the possibilities for effectively 

and economically ensuring reliability. 

These technologies have also called into question the most basic 

tenets of rate making and have challenged the longstanding financial model for utilities. These are enormous and complex matters 

that require careful examination by this committee. At the end of 

the day, we may decide that we need to make changes to the Federal Power Act or we may conclude that we should make no 

changes and continue to allow developments in the states and the 

courts to drive policy. 

It is critical that our committee, at a minimum, take the time we 

need to examine these matters so that we arrive at decisions that 

are informed by fact and that serve the interests of our districts, 

our states, and the nation as a whole. 

And at this time I would like to yield the balance of my time to 

Mr. McNerney. 

[The prepared statement of Mr. Pallone follows:] 

PREPARED STATEMENT OF HON. FRANK PALLONE, JR. 

Thank you for holding today’s hearing to provide us with a market participant 

perspective on our system of electricity regulation. 

Today’s hearing picks up on an issue that you started to focus on last Congress, 

Mr. Chairman, with our insightful hearing on the Federal Power Act. Like that 

hearing, today’s hearing was developed in partnership between you and Chairman 

Walden and me and Ranking Member Rush. This is set up to be a completely nonpartisan hearing with the goal of providing us important background for future decisions. 

I also want to welcome our witnesses, particularly Tammy Linde from New Jersey’s PSEG. And I’d like to welcome back to the committee a former counsel for this 

Subcommittee and FERC Chair, Joe Kelliher. 

As I said previously, while our attention to electricity issues has been sporadic 

since the passage of the Energy Policy Act of 2005, there was a time when it seemed 

like this committee held hearings on the electric sector almost weekly. Now, developments in the electricity sector and the regional markets, both promising and concerning, require us to return again to a serious assessment of the state of the electric sector and how it is regulated. 

9 

Technology has dramatically transformed the possibilities for cost-effectively generating and efficiently delivering electric energy to homes, businesses and manufacturing facilities from a variety of sources. Distributed generation -both fossil and renewable based- along with improving storage options, smart meters, microgrids and 

other technologies— have altered the possibilities for effectively and economically 

ensuring reliability. These technologies have also called into question the most basic 

tenets of ratemaking, and have challenged the long-standing financial model for 

utilities. 

These are enormous and complex matters that require careful examination by this 

Committee. At the end of the day we may decide that we need to make changes 

to the Federal Power Act, or we may conclude that we should make no changes and 

continue to allow developments in the states and the courts to drive policy. It is critical that our Committee, at a minimum, take the time we need to examine these 

matters so that we arrive at decisions that are informed by fact and that serve the 

interest of our districts, our states and the nation as a whole. 

Thank you, I yield back. 

Mr. MCNERNEY. Well, I thank the ranking member, and I thank 

the chair for holding this hearing. I want to welcome the witnesses, 

in particular Mr. Schleimer from Calpine. 

The electric grid has long provided Americans with reliable and 

affordable power upon which our economy depends. Today we see 

big changes though in our electric grid such as the challenge of reducing carbon emissions, distributed generation, cyber and physical 

threats, as well as rapidly developing technology. 

Our nation depends on laws and regulations that encourages and 

allows utility companies to adapt and thrive. I look at this series 

of hearings as an opportunity to be informed in our legislative process which should be both bipartisan and productive, so I thank the 

witnesses and I yield back to the ranking member. 

Mr. PALLONE. And I yield back also, Mr. Chairman. 

Mr. UPTON. The gentleman yields back. With that we are ready 

to hear the testimony and do our normal Q & A. Thank you, panel, 

for being here. 

And we are going to start with the senior guy, the guy who spent 

a lot of hours here, a lot of weeks and months, so over the years, 

Joe Kelliher. Joe, welcome back. Thank you. 

It is a new mic so you have got to push the button, still. 

STATEMENTS OF JOSEPH T. KELLIHER, EXECUTIVE VICE 

PRESIDENT, FEDERAL REGULATORY AFFAIRS, NEXTERA ENERGY, INC.; LISA G. MCALISTER, SENIOR VICE PRESIDENT 

AND GENERAL COUNSEL FOR REGULATORY AFFAIRS, AMERICAN MUNICIPAL POWER, INC.; STEVEN SCHLEIMER, SENIOR 

VICE PRESIDENT OF GOVERNMENT & REGULATORY AFFAIRS, CALPINE; JACKSON REASOR, CHIEF EXECUTIVE OFFICER, OLD DOMINION ELECTRIC COOPERATIVE; TAMARA 

LINDE, EXECUTIVE VICE PRESIDENT AND GENERAL COUNSEL, PUBLIC SERVICE ENTERPRISE GROUP, INC.; KENNETH 

D. SCHISLER, VICE PRESIDENT OF REGULATORY AND GOVERNMENT AFFAIRS, ENERNOC; AND ALEX GLENN, SENIOR 

VICE PRESIDENT OF STATE AND FEDERAL REGULATORY 

LEGAL SUPPORT, DUKE ENERGY 

STATEMENT OF JOSEPH T. KELLIHER 

Mr. KELLIHER. Mr. Chairman, Mr. Upton, Mr. Rush, members of 

the subcommittee, I appreciate the opportunity to testify today on 

the state of the U.S. electricity industry. My name is Joe Kelliher. 

10 

I am Executive Vice President for Federal Regulatory Affairs for 

NextEra Energy. 

NextEra Energy is one of the largest generators in the United 

States. We have nearly 40,000 megawatts in the United States and 

Canada, and of the larger generators, NextEra has perhaps the 

most diverse electricity supply. We are also one of the relatively 

few numbers of truly national electricity companies. We operate in 

every regional power market in the United States and I offer the 

perspective of a competitor in those markets as well as the perspective of a former energy regulator. I was chairman of FERC for a 

number of years and a commissioner at FERC and a former counsel of this committee. 

Since the 1980s and 1990s, the federal government has promoted 

competition in the wholesale power markets in order to lower rates 

to customers based on the belief that competitive markets provide 

greater efficiencies than traditional cost-of-service rate regulation 

and the goal of competition policy is lowering cost and shifting risk 

from customers to competitors. 

The U.S. electricity industry, as members have noted in opening 

comments, is undergoing a major transition. The market fundamentals driving this transition include a dramatic increase in 

U.S. natural gas production, the resulting sharp and sustained decline in natural gas prices, significant declines in wholesale power 

prices, lower than expected electricity demand, and improvements 

in the efficiency and cost of new wind and solar generation. 

Low wholesale power prices have led to sizable retirement of inefficient and uneconomic older coal and natural gas generation facilities, some retirement of uneconomic nuclear units, and large additions of modern, efficient natural gas and renewable energy generation. As a result, the U.S. electricity supply today has changed 

significantly and is now more diverse than our electricity supply 

has ever been up to this point. 

These changes have been so significant as to raise concerns about 

whether these generation retirements are being driven by market 

fundamentals or by federal and state policy and whether the retirement of uneconomic generation poses a threat to electric system reliability. The evidence strongly suggests that the primary factor 

driving retirements has been market fundamentals not regulatory 

policy, and there is no evidence to suggest that the retirement of 

uneconomic generation poses a threat to electric reliability. 

A number of states have proposed programs designed to prevent 

the retirement of uneconomic generation for a mix of policy rationales. To be clear, the market failure addressed by these state programs is low wholesale power prices, and the solution to this problem is to raise prices charged by a select few which would tend to 

suppress the prices for everyone else and discourage the entry of 

new, more efficient generation. 

These proposals shift risk away from competitors back to consumers which is contrary to a central goal of competition policy 

itself. These state programs are controversial and they have been 

challenged in both federal and state courts. Some have been overturned, one was recently upheld, and other challenges remain 

pending. Because these state programs threaten the integrity of 

wholesale power markets, FERC is presented with some hard deciVerDate Nov 24 2008 15:59 Feb 12, 2018 Jkt 037690 PO 00000 Frm 00016 Fmt 6633 Sfmt 6633 I:\MY DOCS\HEARINGS 115\HEARINGS\115-45 CHRIS
11 

sions on how to balance respect for state policy choices with its 

legal duty to assure just and reasonable prices. 

This balancing though necessarily involves placing a lesser priority on efficiency and low cost, and in my view FERC has a legal 

duty to protect market integrity. 

I believe our electricity markets are working well and are workably competitive. U.S. electricity markets are undergoing a major 

transition driven by market fundamentals, the result of low natural gas produced by the shale gas revolution combined with increased efficiency, low demand, and low wholesale power prices. 

This transition has been marked by major changes in our electricity supply mix. We are seeing tremendous diversity in technology change. This transition is likely to continue, producing an 

increasingly diverse and more reliable electricity supply. 

As someone who bears the scars of the California crisis of 2000– 

2001, I admit that it feels strange to testify at a congressional 

hearing on the problem of low wholesale power prices and possible 

solutions to that problem. And I have to wonder if wholesale power 

prices were much higher we might not be having this hearing or 

we would have a completely different focus. 

But that is just a point that we should keep the consumers in 

mind as we discuss these issues. While it is painful for many competitors, the transition of electricity markets has delivered significant benefits to consumers in the form of lower prices, and we have 

to accept the fact that while low wholesale prices can be painful for 

the owners of uneconomic generation facilities they are ultimately 

good for consumers and great for America. 

And with that, I thank you for inviting me, and I look forward 

to questions. 

[The prepared statement of Joseph T. Kelliher follows:] 

12 


26883.001

Testimony of Joseph T. Kelliher 

Executive Vice President- NextEra Energy, Inc. 

Before the Subcommittee on Energy 

Committee on Energy and Commerce 

U.S. House of Representatives 

"Powering America: Examining the State of the Electric Industry through Market 

Participant Perspectives" 

July 18, 2017 
13 


26883.002

Introduction 

Mr. Chairman, Members of the Subcommittee, I appreciate the opportunity to testify 

today and offer my perspective on competitive wholesale power markets and the challenges 

facing those markets. I applaud the Subcommittee for its attention to this subject. I offer the 

perspective of a former Chairman of the Federal Energy Regulatory Commission (FERC), 

Executive Vice President of Next Era Energy, Inc., and a former Counsel of this Committee who 

was responsible for electricity issues. I appear today on behalf of NextEra Energy, one of the 

largest electric generators in the U.S., the third largest investor in American infrastructure, 

behind only AT&T and Verizon, and one of the very few electric energy companies that 

operates in every regional power market in the country. 

Next Era Energy is a leading clean energy company with consolidated revenues of 

approximately $16.2 billion, approximately 45,900 megawatts of generating capacity, and 

approximately 14,700 employees in 30 states and Canada. Headquartered in Juno Beach, 

Florida, NextEra Energy's principal subsidiaries are Florida Power & light Company, which 

serves approximately 4.9 million customer accounts in Florida and is one of the largest rateregulated electric utilities in the United States, and NextEra Energy Resources, LLC, which, 

together with its affiliated entities, is one of the nation's largest natural gas generators and the 

world's largest generator of renewable energy from the wind and sun. Through its subsidiaries, 

Next Era Energy generates clean, emissions-free electricity from eight nuclear power units in 

Florida, New Hampshire, Iowa and Wisconsin. 
14 


26883.003

U.S. Electricity Markets 

There are two basic electricity markets in the United States, wholesale markets 

regulated by the Federal Energy Regulatory Commission (FER C) and retail markets subject to 

state jurisdiction and regulation by state public utility commissions. There are two types of 

wholesale power markets, organized markets administered by regional transmission 

organizations (RTO) and independent system operators (ISO), and bilateral markets governed 

by bilateral power purchase contracts between generators and utilities. Roughly two-thirds of 

U.S. electricity consumption occurs in the RTO and ISO markets, while bilateral markets are 

concentrated in the southeast and non-California West. 

Of course, wholesale and retail markets interact with each other, and the legal and 

jurisdictional boundaries between these markets are not always clear. Because of that interrelationship there has always been some tension between federal and state electric regulation, 

but my experience is that both federal and state regulators work very hard to respect each 

other's responsibilities in a manner that minimizes conflict. 

Wholesale Competition 

Wholesale markets are competitive, both in the organized RTO and ISO markets and 

bilateral markets. Competition policy has its roots in policy decisions made by FERC in the 

1980s and 1990s, relying on authority granted to it by Congress in 1935. FERC promoted 

competition in wholesale power markets in order to lower rates to customers, in the belief that 

competitive markets provide greater efficiencies than traditional cost-based rate regulation. 

FERC believed competition would lower costs and shift risk from customers to competitors. 

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FERC encouraged competition by authorizing wholesale power sellers to charge marketbased rates instead of cost-based rates. It further encouraged competition by requiring open 

access to the transmission grid, preventing grid owners from discriminating against competing 

wholesale sellers. 

While wholesale markets are competitive, they are not deregulated. That is, wholesale 

sellers are subject to a panoply of market rules, as well as anti-manipulation rules issued under 

authority granted by Congress in the Energy Policy Act of 2005. In other words, wholesale 

markets are governed by both competition and regulation, a form of hybrid competition. 

FERC understands that while competition may lower costs and deliver customer 

benefits, it will not always be kind to competitors. From the beginning, FERC recognized that 

competition will penalize sellers that are inefficient or have higher cost generation facilities. In 

short, competition policy does not necessarily benefit all competitors, and the exit of high cost 

generators is a necessary feature of competitive wholesale power markets. 

State of U.S. Electricity Industry 

The U.S. electricity industry is undergoing a fundamental transition. The market 

fundamentals driving this transition include a dramatic increase in U.S. natural gas production, 

the resulting sharp and sustained decline in natural gas prices, significant declines in wholesale 

power prices, displacement and retirement of inefficient coal, natural gas and oil-fired 

generation, lower than anticipated electricity demand, the addition of modern, efficient natural 

gas generation, and improvements in the efficiency and cost of new wind and solar generation. 

Contributing to these market forces are federal and state policies encouraging renewables, and 

stricter controls on emissions from fossil generation facilities. 

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26883.005

Of these factors, the most important by far have been low natural gas prices in concert 

with the addition of highly efficient new gas generation. When combined with lower demand 

growth, the result is low wholesale power prices, rendering generation from older, inefficient 

facilities uneconomic. Importantly, the sharp decline in natural gas prices changed the 

longstanding relationship between coal and gas generation, making gas generation significantly 

lower cost than coal for the first time- that is the real game changer. 

There has been sizeable retirement of inefficient and uneconomic older coal and natural 

gas generation facilities, some retirement of uneconomic nuclear units, and large additions of 

modern, efficient natural gas and renewable energy generation. As a result, the U.S. electricity 

supply mix has changed significantly over a relatively short period, and there is now more 

diversity in U.S. electricity supply than ever before. The coal share of our electricity supply mix 

declined from 47% in 200S to 31% in 2016, the natural gas share rose from 22% to 33% over the 

same period, and wind and solar now account for 7% of our supply. Overall, the mix of U.S. 

electric generation facilities is younger, more efficient, more varied in size and technology, and 

more flexible than ever before. 

These changes have been so significant to have raised concerns about whether 

generation retirements are being driven by market fundamentals or by federal or state policy, 

and whether the retirement of uneconomic generation poses a threat to electric system 

reliability. The evidence strongly suggests that the primary factor driving retirements has been 

market fundamentals, not regulatory policy, and there is no evidence to suggest the retirement 

of uneconomic generation poses a threat to electric reliability. Because the transition is driven 

by market fundamentals, it can be expected to continue. 

4 
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While there are concerns in some quarters that future retirements may result in a loss 

of electricity supply diversity, the reality is the ongoing transition is likely to result in even 

greater diversity through the addition of electricity storage and distributed resources. 

The retirement of inefficient and uneconomic generation is a natural aspect of a 

competitive market, and the exit of uncompetitive assets produces consumer benefits. Given 

the outlook for U.S. natural gas supply and prices and continued improvements in wind and 

solar efficiency and cost, the pressure for uneconomic facilities to exit may not relax. 

Wholesale competition policy played a role in this transition. Lowering costs was the 

primary goal of competition policy and competition has helped maximize the benefits of the 

shale gas revolution. Competition policy also successfully shifts risk away from customers to 

market participants, and competitive markets facilitate deployment of new technologies. 

Challenges Facing Competitive Wholesale Markets 

While wholesale markets are working to drive down prices and to drive out 

inefficiencies, there are some who argue there is systemic "market failure" that must be 

corrected. Some critics who allege market failure fault competitive markets for not achieving 

goals these markets were never designed to meet in the first place. Markets were not designed 

to encourage diversity, retain uneconomic facilities, or achieve environmental goals- they 

were designed to result in an efficient outcome for consumers they were designed to result in 

lower power costs and shift risks from consumers to competitors. 

Though competitive markets are working, they face a number of challenges. The 

organized RTO and ISO markets are governed by complex market rules, and critics focus on that 

complexity, but complexity alone is not a sign of market failure. These markets are dynamic, so 

5 
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RTOs and ISOs must continuously consider the need for market rule improvements intended to 

produce the correct outcomes, an aspect of their duty to protect market integrity. To the same 

end, FERC directs RTOs and ISOs to reform their rules from time to time. 

There is always some tension between federal and state electric regulation. States have 

long had responsibility for integrated resource planning of electric generation in their states, 

particularly in states with vertically integrated utilities. As a general matter, FERC respects state 

policy decisions when they pose little harm to wholesale markets. But proposals by some 

states to prevent the exit of uneconomic generation not needed for electric reliability threaten 

the integrity of wholesale markets. States have different rationales for these programs. 

To be clear, the fundamental "market failure" addressed by these proposals is low 

wholesale power prices, but low prices by themselves cannot be considered market failure if 

driven by market fundamentals, as they appear to be. The "solution" to the "problem" of low 

prices is to raise prices charged by a select few, which would tend to suppress prices for 

everyone else, discouraging the entry of new, more efficient economic generation. 

In the end, these types of proposals shift risk away from generators back to customers, 

contrary to a primary goal of competition policy. In effect, the owners of uneconomic 

generation facilities get a safe haven from the risk of competitive markets. 

As you can imagine, these state programs and proposals are controversial. They have 

been challenged in the courts, and some have been preempted by federal law or otherwise 

found unlawful. Currently, there are legal challenges pending in federal and state courts. 

Because of the tendency of these programs to suppress wholesale power prices, FERC is 

presented with difficult decisions on how to balance respect for state policy choices with its 

6 
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26883.008

duty to protect market integrity and assure just and reasonable prices. It remains to be seen 

how FERC will balance these important interests. 

Conclusion 

In conclusion, I believe our electricity markets are working well and are workably 

competitive. U.S. electricity markets are undergoing a fundamental transition driven primarily 

by economics, the result of low cost natural gas produced by the shale gas revolution combined 

with increased energy efficiency, lower demand growth, and low wholesale power prices. The 

transition has been marked by an increase in new, more efficient natural gas generation, a 

significant increase in ever-lower cost wind and solar generation, and the retirement of 

inefficient, uneconomic generation. This transition is likely to continue, producing an 

increasingly diverse and more reliable electricity supply. We should keep the consumer in 

mind. While painful for many competitors, this transition has delivered significant benefits to 

the consumers in the form of lower prices. We have to accept the fact that, while low 

wholesale prices can be painful for the owners of uneconomic generation facilities, they are 

ultimately good for consumers and great for America. 

7 
20 

Mr. UPTON. Thank you very much. 

Next, we are joined by Lisa McAlister, Senior VP and General 

Counsel for Regulatory Affairs at American Municipal Power, Inc. 

Welcome. 

STATEMENT OF LISA G. MCALISTER 

Ms. MCALISTER. Thank you and good morning, Chairman Upton, 

Vice Chairman Olson, Ranking Member Rush and distinguished 

members of the subcommittee. My name is Lisa McAlister, and I 

am the Senior Vice President and General Counsel for Regulatory 

Affairs for American Municipal Power. 

AMP is a nonprofit wholesale power supplier and service provider for 135 members across nine states with the majority of 

AMP’s members in the PJM region. AMP is one of the largest public power, joint action organizations in the country and has generating facilities and/or members located in the districts of the following subcommittee members: Congressmen Griffith, Johnson, 

Latta, McKinley, Shimkus, and Walberg. 

At the outset I want to make clear that AMP supports competitive electric markets. They offer opportunities for our members to 

serve their customers at the lower cost. AMP also strongly supports 

reliability, but as a member-focused organization we work hard to 

ensure that the benefits of regulatory changes made to improve reliability justify the costs to consumers. While the energy portion of 

wholesale bills is the most substantial portion, capacity and transmission are quickly becoming more significant and growing. 

AMP has serious concerns about PJM’s capacity construct and 

also the growing transmission costs. My written testimony provides 

more details and examples of the challenges that AMP and our 

members have faced in these areas. PJM’s current administrative 

capacity construct called the reliability pricing model, or RPM, is 

not a market in any meaningful sense. Rather, RPM is a complex, 

rules-driven, administrative mechanism for pricing and procuring 

capacity that relies on distinctly non-market features. 

PJM’s capacity construct requires constant modifications to 

achieve the desired outcomes and is becoming increasingly complicated bringing increased volatility and so much rules churn that 

long-term planning is extremely difficult. We are moving away 

from markets. 

One alternative solution is for local utilities known as load serving entities, or LSEs, to satisfy most or all of their capacity needs 

through bilateral arrangements in a real marketplace where there 

are willing buyers and sellers and they negotiate arrangements to 

meet their needs. Under an approach like this, each local utility or 

LSE would secure capacity to meet its peak load obligation plus a 

predetermined reserve margin bilaterally on a long-term portfolio 

basis. The RTOs would still have a significant role in determining 

the peak load obligations, identifying constraints on the system, 

and conducting a residual action. And this alternative has numerous advantages over the current capacity constructs including 

fewer moving parts and administrative judgments, harmonization 

between states and local policies, avoidance of jurisdictional disputes, and also flexibility for both states and generators. 

21 

It is important also for us to touch on transmission. Nationally, 

transmission costs have increased dramatically. For example, in 

four of AMP members’ transmission zones, annual revenue requirements have increased by a range of 99 to 214 percent from 2009 

through 2016. AMP understands that there are many drivers increasing transmission costs and AMP’s members are willing to pay 

their fair share of the cost. But AMP has to work very hard to 

make sure these costs lead to the most cost effective and efficient 

grid expansion. 

The transmission planning process must be open and transparent, must provide equitable treatment, and take into account 

the changing resource mix and configuration of the future, rather 

than a piecemeal replacement of the grid of the past. While it is 

essential for developers to earn a fair return on their investment, 

these rates should reflect current economic conditions and risks. 

AMP supports Congress playing a more active role and encouraging FERC to refocus on its statutory mandate to ensure just and 

reasonable rates. Enhanced congressional oversight is critical to ensure that FERC is responsive to the real needs of customers. 

Congress can be helpful by insisting that keeping costs to consumers as low as possible is a central part of the RTO mission; reiterating that load serving entities have a right to make generation 

choices that are not subject to rejection by the RTOs or FERC; insisting that resource adequacy constructs must accommodate state 

and public policy decisions; ensuring that RTO governing boards 

are representative, open, transparent, and independent from RTO 

management; requiring RTOs to demonstrate how the proposed 

market changes benefit customers; directing FERC and the RTOs 

to develop robust and consistent transmission planning criteria; 

and encouraging FERC to ensure that return on equity rates for 

transmission investments reflect current economic conditions and 

risk levels. 

Thank you for the opportunity to appear before you today, and 

I would be happy to answer questions. 

[The prepared statement of Lisa G. McAlister follows:] 

22 


26883.009

U.S. House Subcommittee on Energy 

Hearing on Powering America: Examining the State of the Electric Industry 

Through Market Participant Perspectives 

July 18, 2017 

Written Testimony of 

Lisa G. McAlister 

Senior Vice President and General Counsel of Regulatory Affairs, 

American Municipal Power, Inc. (AMP) 

Summary Points: 

• American Municipal Power, Inc. (AMP) is the non-profit wholesale power supplier and 

service provider for 135 member municipal electric systems across nine states -with 

a majority of AMP's members being load-serving entities within the PJM region. 

• AMP supports competitive markets, reliability and affordability but believes that the 

current capacity constructs in PJM are flawed and need a comprehensive review (in 

conjunction with the energy and ancillary services markets) of the cumulative impacts 

of PJM's overall market design on consumers. 

• PJM's current capacity construct is a complex rules-driven administrative mechanism 

for pricing and procuring capacity that relies on distinctly non-market features. Over 

time, PJM's capacity construct has become less flexible and is incapable of 

accommodating state and public policy decisions. 

• It is time to consider alternatives to the current capacity construct and AMP supports 

the broader use of bilateral contracting for load-serving entities, like AMP, to satisfy 

most or all of their capacity needs. 

• AMP supports appropriate transmission infrastructure build-out to replace aging 

infrastructure. However, there needs to be more transparent transmission planning, 

equitable treatment, better oversight to ensure the most cost-effective and efficient 

grid expansion, and rates of return that reflect current economic conditions and risks. 

• We support Congressional oversight and commend this Subcommittee for taking up 

these important matters. 
23 


26883.010

Good morning, Chairman Upton, Vice Chairman Olson, Ranking Member Rush and 

distinguished members of the Subcommittee. My name is Lisa McAlister and I'm the 

Senior Vice President and General Counsel for Regulatory Affairs of American Municipal 

Power, Inc. (AMP). I'm pleased to have the opportunity to appear before you this morning 

to discuss the state of the electric markets in the Eastern Regional Transmission 

Organizations (RTOs) and my focus will be on the PJM Interconnection, LLC (PJM). 

AMP has a unique vantage point on the state of the wholesale energy and capacity 

markets, the transmission planning that PJM oversees, and the impact of these policies 

on electric consumers. AMP is the non-profit wholesale power supplier and service 

provider for 135 member municipal electric systems across nine states- with a majority 

of AMP's members being load-serving entities (LSEs) within the PJM region. We are an 

active participant in the PJM stakeholder process and an active litigant in many of the 

administrative cases before the Federal Energy Regulatory Commission (FERC) that 

address the myriad changes to the PJM markets. AMP commends the Subcommittee for 

holding this hearing and appreciates the opportunity to share its perspective, and looks 

forward to discussing these matters further during the hearing. 

The electric industry has experienced a number of changes throughout the past 

few decades- principally driven by regulatory actions. However, a discussion of the state 

of the electric industry must recognize that technology developments will be the principal 

driver to the changes confronting our industry going forward - be those grid 

modernization, customer-sited generation, shale gas, energy storage or cyber. While my 

remarks today will not focus on those technologies, AMP recognizes those drivers and 

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we're working with our member municipal electric systems to ensure they have the tools 

needed to be prepared to meet their customer needs. 

AMP is a member-focused organization and our members are customer-focusedtherefore, the lens through which we view the impact of market changes is to ensure that 

the benefits of regulatory changes to improve reliability justify the costs to consumers. 

I. Background 

As you know, in the 1990s, the government decided to restructure the electricity 

industry, breaking vertically integrated utilities into generation and wires businesses and 

introducing competition in the generation sector. As the competitive market for generation 

began to emerge, it became clear that an impartial "traffic cop" with the authority to 

enforce grid reliability and operate the electric grid in a nondiscriminatory basis was 

needed to mitigate market power resulting from continued vertical integration of investorowned utilities. FERC's landmark Orders 888, 889 and 2000 created independent system 

operators (ISOs), which have since become known also as regional transmission 

organizations (RTOs). Additional reforms by FERC and Congress continued the progress 

towards electricity market restructuring. With that progress came evolution of the RTOs 

and the development of RTO-run centralized wholesale markets. 

Specifically, PJM began using locational marginal pricing {LMP) to set prices for 

energy purchases and sales in the PJM market and to price transmission congestion 

costs in 1997. FERC's basis for approving this market design was that LMP would send 

the proper price signals as to where generators should locate on the system, and where 

new transmission facilities should be constructed to relieve substantial and continuing 

congestion. But over time, it became evident that PJM's LMP energy market was not 

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26883.012

sending these signals-or at least that these signals were not being adequately 

responded to by market participants, chiefly generators and transmission owners. 

Electric generation owners in particular claimed that the existence of the $1 ,000 price cap 

prevented them from earning sufficient revenues to permit them to make the necessary 

investments. The "missing money problem" was repeatedly cited as justification for 

providing a separate locational capacity revenue stream for generation owners separate 

from energy market revenues. Accordingly, PJM developed its administrative capacity 

construct, called the Reliability Pricing Model (RPM). Again, the justification for RPM 

came down to the lack of a requirement for a long-term forward commitment for capacity 

as an obstacle to capacity resources being able to project an adequate revenue stream 

going forward. Consequently, PJM argued that the then-current, energy-only construct 

did not provide meaningful price signals to capacity resources of the true value of the 

level of reliability that they provide to the system. 

In spite of the combined revenue that generators can obtain from the energy 

market and RPM capacity construct, as well as PJM's various ancillary services markets, 

the capacity constructs in particular have rapidly morphed beyond their intended purpose 

and require constant modifications to achieve desired outcomes. The capacity constructs 

are becoming increasingly complicated, bringing increased volatility and so much "rules 

churn" that any long-term planning and coordination is extremely difficult For example, 

PJM's most recent changes add performance requirements that are overly restrictive and 

unnecessary. Further, what used to be an administrative construct to recover "missing 

money" is becoming a major source of revenue - and consumer costs- for many units. 

We are moving away from markets. 

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26883.013

Due to market volatility and the constant rules churn, AMP embarked on a 

generation asset development effort a number of years ago to reduce its market 

exposure. As a result, today AMP has assets of more than $6.7 billion, including coal, 

gas and hydropower projects. Although AMP does own generation assets, AMP and its 

members remain net short on generation capacity and rely on market purchases to meet 

load obligations. Further, because AMP members are transmission-dependent and AMP 

does not own transmission, we rely on PJM and the transmission owners to plan and 

build and provide nondiscriminatory access to the transmission system to get our 

generation to our load. 

II. Capacity Constructs 

On May 1"1 and 2nd of this year, FERC held a technical conference to discuss the 

role of state policies in shaping the quantity and composition of resources needed to costeffectively meet future reliability and operational needs in the Eastern RTOs and ISOs. 

The conference was a forum where FERC and the participants, including AMP, had a 

policy-level conversation about whether centralized capacity constructs are sufficiently 

flexible and robust to integrate state policies, while also satisfying reliability goals and 

meeting the needs of market participants and electric consumers in the face of an evolving 

resource mix. 

Let me be clear at the outset: AMP supports competitive markets. Truly competitive 

markets are important to public power because they offer opportunities for our members 

to serve their customers at a lower cost. But, PJM's current administrative capacity 

adequacy construct is not a market in any meaningful sense. Rather, RPM is a complex 

rules-driven administrative mechanism for pricing and procuring capacity-one that relies 

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26883.014

on such distinctly non-market features as an artificial demand curve, price caps and 

minimum offer price requirements, and obstacles to competition from certain types of 

resources. And while the purpose of a true market is to arrive at the most efficient 

utilization of economic resources, RPM's acknowledged goal is to provide a stream of 

revenues to suppliers to make up for "missing money." RPM is a "market" in name only, 

and, as time has gone on, fewer and fewer PJM market participants use that term to 

describe it. 

Another factor that sets RPM apart from a normal market is that RPM's rules are 

in constant flux. During the ten years RPM has been in effect, PJM has been in a nearconstant state of developing, filing or defending some new set of RPM rules, some of 

which fundamentally changed the nature of RPM. In fact, since 2010, there have been 

27 significant filings made to modify RPM. According to PJM, the 2016 Base Residual 

Auction (BRA) was the first BRA with no rule changes from the prior year. While PJM 

may view each set of rule changes as necessary to address some unforeseen events or 

to provide market design improvements, the constant "rules churn" that is RPM has a 

number of negative impacts. The ongoing accumulation of rules and patches to rules, for 

example, has produced an unduly complicated mechanism; at this point, in fact, RPM's 

complex web of rules, exceptions, and exceptions to exceptions is such as to confound 

many market participants while, at the same time, providing a cloak for gaming behavior 

by others. Furthermore, the ever-changing nature of RPM's rules makes long-term 

resource planning and coordination next to impossible. These dysfunctional attributes are 

manifest in the fact that, even after more than a decade of operation and countless tweaks 

and patches, RPM still falls woefully short in terms of its ability to: 

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• ensure reasonable, transparent and stable capacity prices; 

• in cent required levels of electric infrastructure development; 

• promote fuel diversity (PJM has grown heavily dependent on natural gas 

generation); or 

• provide any assurance that in the long term sufficient resources will be built 

to meet the region's reliability needs. 

During FERC's September 25, 2013 Technical Conference on Centralized 

Capacity Constructs, PJM delivered a report on RPM's goals and its claimed successes 

in several areas, including that of bringing forth the right capacity investments in the right 

locations. Yet, less than a year later, PJM believed it necessary to propose a fundamental 

overhaul of RPM in the form of its Capacity Performance (CP) proposal. Touted as a 

response to the polar vortex of early 2014, CP was rich in features that were uniquely 

disruptive and burdensome for stakeholders, such as unreasonable operational 

performance requirements, a paradigm shift for seasonal resource participation, penalties 

disconnected from the value of performance at the time and with the potential to exceed 

capacity revenue, and a near complete unwinding of the market mitigation rules governing 

offer caps, to name a few. Rather than seeking to meet the challenge of extreme 

demands by adding flexibility to PJM's capacity construct, CP instead adopted an 

inflexible product definition that discourages fuel and technology diversity by imposing 

strict performance requirements which disregard the fact that, even among the most wellmanaged units, there will be variations in forced outage rates, fuel supply arrangements, 

ramping rates and minimum load levels, and environmental restrictions, among other 

things. And because CP imposes unduly discriminatory restrictions and requirements on 

the use of renewable and demand response resources, a whole family of resources that 

historically provided significant value to the region now are greatly hampered in the value 

7 
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26883.016

they can bring. For example, as a result of feedback and strategic direction from our 

members and their customers, AMP made decisions to develop four new hydroelectric 

facilities totaling over 300 MW at an investment cost of nearly $3 billion. Those local 

decisions were reached in furtherance of a power supply strategy that incorporates longlived (80-100 year) emission-free resources to avoid market volatility, and were pursued 

irrespective of RPM price signals or its three-year look-ahead. However, as a result of 

the move to CP, AMP cannot get full value for its hydroelectric infrastructure as they 

cannot guarantee 24/7/365 operation. This is the case because AMP cannot control the 

river flows and cannot practically back up the hydroelectric plants with an alternative 

generation resource. In making PJM's capacity construct less flexible, CP also has made 

it less capable of integrating the diversity of resources that may be an element of 

implementing important state policies. 

Another example of the unreasonable effect of CP on AMP specifically has been 

to put AMP at risk of not being able to use its coal resource in one RTO (MISO) to serve 

its load in another RTO (PJM). With FERC's acquiescence, and against AMP's protests, 

FirstEnergy and Duke Energy withdrew from MISO to participate in PJM. A sizable 

number of AMP's members are served from the transmission facilities owned by 

FirstEnergy and Duke, so prior to those companies' RTO "realignment," a considerable 

portion of AMP's member load was located within MISO. That was the situation that 

existed when AMP negotiated the purchase of its 368 MW share of the Prairie State 

Generating Campus (Prairie State). When FirstEnergy and Duke moved into PJM, 

however, the interconnected AMP members were compelled as a practical matter to 

move into PJM, as well. Consequently, AMP found itself in the situation in which Prairie 

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26883.017

State and other supply resources remained within MISO while most of its load was located 

in PJM. That outcome was one over which AMP had no control and it is the situation that 

continues to this day. However, today PJM's new CP rules require all capacity resources 

physically located outside of PJM to pseudo-tie into PJM to qualify as capacity resources. 

Thus, in order to utilize Prairie State for its intended purpose- namely, providing longterm power supply service to AMP's members in an economical and reliable manner (and 

not to take advantage of more advantageous market conditions in one RTO or the other), 

AMP is required to use a pseudo-tie arrangement to offer AMP's Prairie State share into 

PJM's capacity auctions. However, the pseudo-ties are currently under attack from 

competitive generators and other RTOs, among others. If AMP's use of that pseudo-tie 

becomes burdened to the point that it is rendered uneconomic, AMP's members would 

be deprived of the intended benefits of a resource in which AMP has invested significant 

capital and resources to serve its members. 

More recently, PJM has faced another development it seems to view as a 

challenge to RPM-namely, the efforts by some states and LSEs to take a direct role in 

guiding the resource mix in order to implement state policies. These efforts have taken 

the form of legislatively required affiliate power purchase agreements (Ohio) that some 

market participants have opposed as "out of market threats" to RPM. FERC's questions 

in the April 13 Notice of Technical Conference suggest that it, too, has concerns about 

the impacts that policy-implementing payments to capacity resources may have on 

current RTO capacity constructs. An effort to distinguish between state actions that are 

"inside" versus "outside" the market would be misplaced, however, especially if the 

purpose of the distinction is to insulate the current capacity constructs from the "outside" 

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26883.018

influence of state policies. The reality is that, today, there already are factors at work that 

could be portrayed as "out of market" subsidies or advantages, such as state or local tax 

incentives, differing access to certain financing methods or vehicles, and variations in the 

cost of financing. Each of these factors ultimately has its roots in a particular state or local 

policy that may have differing effects across the spectrum of market participants and 

resources. Given this history, it is reasonable to expect that state and local governments, 

who are closer to and likely to take their cues from ultimate consumers, will continue in 

their efforts to guide asset decisions toward those that comport with relevant policies (as 

well as their long-term planning goals) regardless of the short-term and volatile signals 

produced by RPM and for reasons unrelated to the administrative determination of net 

Cost of New Entry (CONE) or Energy and Ancillary Services offsets. In a true market, 

nothing is truly "out of market." 

AMP and its members, for example, retain the obligation to serve customers and, 

thus, AMP makes long-term strategic decisions, like whether to add distributed generation 

or deploy Advanced Metering Infrastructure, based upon the feedback and direction of 

our members and their customers. AMP is not alone; each state has valid environmental, 

political and policy goals that factor in a plethora of local and state considerations beyond 

the ability of a mechanistic administrative construct to accommodate. Consumers, and by 

extension their elected officials, are the parties best positioned to assign value to 

externalities in resource decision making. Self-supply is at the very core of public power's 

organizational model, and AMP's existence. An administrative construct that fails to 

accommodate those choices (because it can't) will always be "missing money." 

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26883.019

PJM needs a resource adequacy construct that is robust enough to withstand the 

effect of external events without the need to adopt another set of complex rule changes 

in response to each event. There are alternatives to the current centralized capacity 

constructs that, in concert with the energy and ancillary services markets and shortage 

pricing, would be more resilient to external events. Simpler, more robust alternatives to 

RPM and centralized capacity constructs exist. 

One such alternative is for LSEs to satisfy most or all of their capacity needs 

through bilateral arrangements, in a real marketplace where willing buyers and willing 

sellers negotiate arrangements tailored to meet the parties' individual wants and needs 

(e.g., as to contract term, fuel type and resource flexibility, location on the grid, and 

financial terms), with a capacity auction available to satisfy any residual needs. Under 

such an approach, the RTO would retain its role of developing and specifying resource 

adequacy requirements for its footprint and Local Distribution Companies (LDCs) of 

concern. Each LSE, LDC or other Relevant Electric Retail Rate Authority (RERRA) would 

be responsible for securing capacity to meet its peak load obligation plus a predetermined 

reserve margin and would face significant penalties for failing to do so. LSEs, LDCs and 

RERRAs could procure resources bilaterally on a long-term portfolio basis in compliance 

with their respective resource adequacy requirements. The RTO could then conduct a 

residual auction to accommodate LSEs and supply that did not enter into long-term 

arrangements. This alternative has numerous advantages over current capacity 

constructs, including the following: 

Fewer Moving Parts and Administrative Judgments. Because the 

primary procurement construct is decentralized and bilateral, it eliminates the onerous 

stakeholder processes, disputes and subsequent litigation over discrete features of 

mandatory capacity constructs. 

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26883.020

Harmonization with State and Local Public Resource Policies. This 

proposal appropriately honors state and local resource portfolio and public policy choices, 

and does not bias market rules toward or against specific resource types. 

Avoidance of Jurisdictional Disputes. By appropriately involving state 

and local authorities in the resource adequacy, constrained zone mitigation and market 

power issues, this alternative sidesteps controversy over respective limits of state and 

federal jurisdiction in the capacity market area created by recent court decisions. 

Flexibility for Individual States. This proposal provides each individual 

state within an RTO region with the flexibility to address resource adequacy issues for its 

retail customers that may result from the state's prior decisions regarding retail access. 

An RTO-administered, centralized voluntary capacity market still would be available to 

satisfy residual needs. 

Improved Product Differentiation and Resource Performance. Bilateral 

contracting and other customized arrangements to procure electric resources enables the 

development of tailored products and services that will meet specific needs rather than 

relying solely on generic, lowest common denominator-type capacity products. For 

example, resources with desirable characteristics, such as those with dual fuel capability 

or firm gas transportation contracts that allow for certainty during winter peaks, could be 

appropriately valued and supported without complex and costly performance penalties. 

Choice of Business Models for Merchant Generators. This proposal 

provides merchant generators and resource suppliers a choice as well: they can enter 

into individualized bilateral supply arrangements with LSEs, rely on sales into the residual 

capacity auction (and/or the energy and ancillary services markets) to obtain their 

revenues, or pursue any combination of these approaches. 

In evaluating the viability of the bilateral contracting model, we believe the 

benchmark should be the value bilateral contracting would bring to market efficiency and 

reliability and its amenability to implementing varying state policies, rather than its 

implications for existing centralized capacity constructs. Moreover, in considering this 

alternative to centralized capacity constructs, the policy concerns that might lead LSEs, 

states or local regulatory bodies to favor local generation over distant generation; newer, 

more efficient resources over older, less efficient ones; lower-emitting resources over 

higher-emitting resources, etc., are legitimate concerns deserving of recognition and 

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26883.021

weight, and, second, policymakers will continue pursuing policies at the direction of their 

constituents. Market rules imposed by RTOs to protect administratively derived prices 

under centralized capacity procurement constructs should not erect barriers to meeting 

such policy goals. And, it bears noting, these prices, developed as they are in isolation 

from local consumer input, will be wrong. Capacity is not fungible and not all MWs of 

capacity are created equal. Consumers are in a better position to determine the value of 

a particular fuel or resource. Long-term contracts support legitimate public policy and 

should be encouraged, rather than being considered "out-of-market" subsidies. RTO 

market rules that effectively penalize long-term contracting and self-supply should be 

reformed. 

As a second-tier alternative, and a minimum step to reform the capacity construct, 

public power systems' unfettered ability to self-supply their own loads with their own 

resources at their own costs should be restored. Although the original settlement that 

created PJM's capacity construct guaranteed that capacity resources of public power 

LSEs and other self-supply entities, like AMP, would clear, over time the PJM rules have 

changed and have stripped away guaranteed clearing for self-supply. This has resulted 

from modification of the minimum offer price rules (MOPR) that were deemed necessary 

to mitigate buyer-side market power. Buyer-side market power, also known as 

monopsony power, is defined as the power of a buyer facing many sellers and little to no 

competition from other buyers. N.J. Bd. of Pub. Utils. v. FERC, 744 F.3d 74, 84 (3d Cir. 

2014). The MOPR in PJM, in its original form, had a basis in economic theory: it targeted 

a limited set of new or uprated resources (new gas-fired resources) but did not apply to 

new nuclear, coal, hydroelectric, renewable, or energy storage resources, because these 

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26883.022

resources cannot be developed on a timeframe and at a size that could allow the exercise 

of buyer-side market power. The PJM MOPR has always been applied only to new 

entrants into the capacity market. It properly does not include existing resources as 

existing units have sunk costs that new units do not have. Initially, public power entities 

were exempted from MOPRs in PJM on the basis that they have no incentive to attempt 

to manipulate the market through below market offers. This is true because public 

power's business model effectively prohibits anything other than legitimate self-supply as 

they are non-profit entities whose purpose is to secure long-term supply arrangements at 

the lowest possible cost and they use tax-advantaged and tax-exempt financing to do 

that. There are real obligations that come with using such financing, including: 1) a 

prohibition on both the municipal LSE and any participants in a project financed with taxadvantaged obligations against using the project for anything other than the governmental 

purposes of the municipal LSE or project participant; and, 2) a prohibition against the 

municipal LSE or any project participant using their interest in the project for any activities 

that constitute a "private use" for the entire term the obligations remain outstanding. If a 

public power entity fails to comply with the requirements, the tax status of obligations 

issued by the municipal LSEs could be jeopardized and result in significant economic 

harm. In other words, the federal tax requirements on tax-advantaged obligations that 

are critical to the longstanding business models of public power entities serve as effective 

barriers against such entities building generation as merchant generation, market 

manipulation, or anything other than legitimate self-supply. Nonetheless, due to pressure 

from competitive generators, the MOPR rules were modified to include self-supply 

entities. 

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26883.023

Most recently, on July 7, 2017, the U.S. Court of Appeals for the District of 

Columbia Circuit vacated and remanded back to FERC prior orders that accepted PJM's 

revisions to the MOPR in PJM's capacity auction rules with respect to several aspects of 

a PJM-proposed rate structure: the self-supply exemption, the competitive entry 

exemption, unit-specific review, and the mitigation period, on the basis that FERC 

exceeded the limits of its Federal Power Act Section 205 authority by suggesting 

modifications to PJM's proposal, which PJM accepted. 

As a result of this decision, self-supply entities are squarely at risk of having to pay 

twice to satisfy the same capacity obligation - once for the resource procured outside of 

PJM's resource adequacy construct and a second time to procure through RPM to 

replace self-supply that failed to clear the auction. The decision also does nothing to 

promote consumer welfare as any blanket proposal that replaces lower cost offers with 

higher, administratively determined offers has more to do with maintaining existing sellerside market power than tailoring a real solution to a real problem. 

It is worth noting also that there have been a number of calls, mostly from merchant 

generators, for FERC and/or RTOs to expand the application of MOPR to existing units 

in addition to new gas-fired units. AMP strongly believes that applying MOPR to existing 

units defies rational economic theory; takes more of the auction process behind closed 

doors as PJM and the Independent Market Monitor determine units' costs; and, 

introduces unwarranted uncertainty as generation resources could no longer know 

whether they will clear the market or not, resulting in the unintended consequence of 

severely damaging the bilateral market. 

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Finally, the consumer impacts of market reform alternatives must not be ignored. 

Market participants wishing to protect their economic interests dominate FERC 

adjudicative dockets and RTO stakeholder processes. In these fora, the interests of 

"load"-retail consumers and those charged with protecting them-often are drowned out 

by the self-interested concerns of larger and better-financed participants. 

Ill. Energy Markets 

Of the two wholesale electricity markets, the energy markets are better able to 

value or select additional attributes than the capacity constructs. As a result of FERC's 

last technical conference on this subject in the fall of 2013, FERC has done an admirable 

job in trying to improve price formation. This is the right track. And, while there are new 

technologies with different operating parameters and capabilities we need to address 

(distributed resources, energy storage), we must not lose sight of improving our current 

price formation processes regarding transparency of operator decisions, modeling all 

known constraints, and more accurate price formation rules during periods of 

transmission congestion and volatile fuel prices. 

Improved energy market rules will be essential to address the rapidly changing 

technological demographic of intermittent resources with a zero energy cost. New energy 

products will be needed to allow RTOs to properly dispatch and balance the system, even 

at high levels of penetration by intermittent resources. For that reason, new energy 

products also must incentivize the retention of sufficient non-variable resources to ensure 

load continues to be served when intermittent resources are not generating. 

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IV. Transmission 

AMP would be remiss to not touch on the third largest (and growing) component 

of wholesale electric bills: transmission. Nationally, transmission costs have increased 

drastically. According to the Edison Electric Institute's (EEl) December 2016 

Transmission Projects at a Glance, increases in year-over-year total transmission 

investment by EEl's members reached approximately $20.1 billion in 2015 and are 

expected to increase through 2017 to a peak of approximately $22.5 billion in 2017. The 

Brattle Group, in a 2015 presentation to a JP Morgan Investor Conference, demonstrated 

these costs have been increasing exponentially since 1995. The build-out trend is 

expected to continue at a rate of $5 to $10 billion annually as infrastructure built in the 

1960's reaches the end of its life and is replaced. According to Navigant, global spending 

on large-scale transmission system infrastructure for renewable energy integration is 

expected to grow from $36.7 billion in 2016 to $46.7 billion in 2025. 

Locally, AMP's members have experienced similar increases over the past eight 

years. In four of AMP members' transmission zones, annual revenue requirements have 

increased by a range of 99 percent to 214 percent from 2009 through 2016. 

AMP's members are willing to pay their share of costs, but must work to make sure 

these costs lead to the most cost-effective and efficient grid expansion. The transmission 

grid must be planned for the future, rather than piecemeal replacement of the grid of the 

past. The transmission planning process must be open and transparent, must provide 

equitable treatment, and take into account the changing resource mix and configuration 

of the future. This can be accomplished by a number of steps. 

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26883.026

More robust planning processes for transparency and replicability are required. In 

PJM, since 2005, almost $198 in projects have been proposed absent transparent criteria 

and models that stakeholders can review and comment on prior to the plans being 

finalized, despite the fact that the transmission owners have turned over the planning and 

operation of their facilities to PJM. These supplemental projects are not needed to 

address any established NERC, PJM or even individual transmission owner criteria. 

In addition to a lack of consistent planning criteria among transmission owners, 

different planning criteria and processes between "different organized markets 

(RTOs!ISOs) hinder inter-regional projects from being built. The interregional planning 

process needs to move away from compartmentalized and multiple threshold evaluations 

and evaluate interregional projects based on their combined benefits across all regions. 

In 2016, AMP and other public power organizations in PJM sponsored a new 

stakeholder effort to address the PJM Transmission Owners' use of Supplemental 

Projects to replace aging transmission infrastructure. This effort was placed on a hiatus 

when FERC issued a show cause order (EL 16-71) with the concern that the PJM planning 

process is not providing stakeholders with the opportunity for early and meaningful input 

and participation in the transmission planning process, as required by Order No. 890. 

The stakeholders agreed to put their effort on hold to enable PJM and the Transmission 

Owners to prepare their responses to this order. With the subsequent lack of a FERC 

quorum, this hiatus was extended until just this month when AMP led a group of 

stakeholders to ensure efforts started back again. The PJM Transmission Owners have 

consistently opposed formation of this group and its returning to work. 

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26883.027

More robust planning models that account for changing grid drivers are also 

required. We need better models via improved software to generate a common model 

that can accurately include all known system constraints. New drivers that must be 

considered include distributed intermittent renewables, smart grid/micro grid 

opportunities, aging transmission facilities, generation retirements and future 

environmental requirements. These drivers could reduce the need for transmission 

investments and failure to consider these factors could result in unnecessary investments 

and higher electric rates. The U.S. Department of Energy (DOE) and FERC must continue 

their focus in this area and fully engage the industry in this endeavor. 

While it is essential for developers to earn a fair rate of return on their investments 

in transmission infrastructure, these rates should reflect current economic conditions and 

risks, and not have the unintended consequence of encouraging building or over-building 

for the sake of revenue generation. Return on Equity (ROE) rates must reflect current 

economic conditions and additional incentives must be awarded judiciously to reflect 

actual levels of risk. 

V. Conclusion 

AMP supports Congress playing a more active role in encouraging FERC to refocus 

on its statutory mandate to ensure "just and reasonable" rates for customers in a 

meaningful way, and to examine whether net customer benefits exist for the multitude of 

RTO market mechanisms deployed, proposed and on the horizon in the Eastern RTOs. 

Enhanced congressional oversight is critical to ensure that FERC is responsive to 

the real needs of consumers. Congress can be helpful by: 

• Insisting that keeping costs to consumers as low as possible be a central part of 

the RTO mission, in addition to promoting electric system reliability; 

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26883.028

• Reiterating that LSEs, through their obligation to serve their customers, have a 

right to make generation resource decisions that are not subject to rejection by 

the RTO or FERC; 

• Insisting that resource adequacy constructs have the flexibility and capability to 

accommodate state and public policy decisions; 

• Ensuring that RTO governing boards are truly representative and open, 

transparent stakeholder boards (i.e., meaning they reflect all load-serving entities 

and hold open meetings); 

• Ensure that RTO governing boards are independent from RTO management and 

act solely in the interest of the RTO, are free from conflicts that compromise 

judgment and are able to take positions in opposition to management; 

• Requiring RTOs to demonstrate that proposed market changes benefit 

consumers (i.e., stop the creation of new markets and products for the sake of 

creating markets and products); 

• Requiring FERC to consider real-world outcomes in its decision-making (including 

balancing consumer, financial, environmental and other impacts); 

• Directing FERC and the RTOs to develop robust and consistent planning criteria 

among transmission owners and RTOs; and, 

• Encouraging FERC to ensure that ROE rates for transmission investments 

reflect current economic conditions and actual risk levels for the investments. 

In closing, I want to stress that AMP supports both competitive markets and 

transmission infrastructure build-out. However, the current capacity constructs are not 

competitive markets. They can and should be simplified to ensure they are achieving the 

policy goals for which they were designed: ensure resource adequacy; balance the 

numerous goals of safety, resource adequacy, consumer affordability, environmental 

sustainability, and financial stability to provide less price volatility to consumers; be 

consistent with the needs of wholesale customers and consumer preferences (and 

operate within the constraints) as reflected through applicable state environmental 

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programs and all other jurisdictional policy objectives; accommodate all types of business 

platforms (merchant or competitive entries, investor owned utilities, and public power selfsupply); facilitate trade to include bilateral contracting and not have market rules that 

restrict the use of available capacity; and produce just and reasonable rates. 

In order to ensure that the right transmission is getting built at just and reasonable 

rates, transmission infrastructure must be designed and built in accordance with FERC 

direction and principles of coordination, openness, transparency, information exchange 

and comparability. Customers and transmission-dependent utilities like AMP and our 

members must have the ability to ensure that planned facilities are indeed necessary and 

economical and must have a meaningful opportunity for review and input after reviewing 

the transmission owners' transparent criteria, assumptions and models. 

Thank you again for the opportunity to appear before you today; I would be happy 

to respond to any questions. 

4830-0383-3931. v. 12 

21 
43 

Mr. UPTON. Thank you. Thanks very much. 

Next, we are joined by Steven Schleimer, senior VP of Government & Regulatory Affairs at Calpine. Welcome, nice to see you. 

STATEMENT OF STEVEN SCHLEIMER 

Mr. SCHLEIMER. Good morning, Chairman Upton, Ranking Member Rush, and members of the subcommittee. Thank you for inviting me to testify today. Calpine is not a regulated utility receiving 

a guaranteed payment from customers. Rather, we compete head 

to head with other suppliers to sell power directly to wholesale and 

retail customers in the competitive markets across the country. 

We have 26,000 megawatts of mostly natural gas-fired combined 

cycles and that is enough to power 25 to 30 million homes. We also 

own the Geysers plant in California which is the largest geothermal facility in the United States. 

The first key takeaway I would like to impress upon you is that 

the competitive markets and particularly in the East Coast and 

Texas have been phenomenally successful. Over the last decade, 

there has been over 50,000 megawatts of new generation either 

committed or entering operations, representing $70 to $80 billion 

of new investment. 

At the same time, as has been noted, wholesale prices are at historic lows, commissions rates are down significantly as well. The 

reserve margin, which is a measure of grid reliability, is significantly higher in each of these regions as well. All of this is clearly 

a win for consumers and the environment. 

However, due to various policy goals and pressure from nuclear 

and coal generators, state policy makers have been increasingly intervening in competitive markets to bail out or subsidize specific 

plants. Examples include the New York and Illinois ZEC program 

along with current attempts to create subsidies in Ohio and Connecticut and nascent attempts in Pennsylvania and New Jersey, 

which were expected. If left unchecked, these efforts threaten the 

continued viability of competition in these regions. Investors are 

simply not going to invest in new infrastructure if they believe 

their direct competitors will receive out of market subsidy payments. 

So now we get to the second key takeaway I would like to impress upon you, the half-in/half-out hybrid market where the state 

relies on the competitive market for some resource needs but then 

target subsidies to select power plants does not work. Once the 

subsidies start, competitive investment stops. 

And how do we know that? We have seen exactly this result in 

California which decided to move away from competition and toward this hybrid half in/half out model more than a decade ago. 

And now new investment only occurs with long-term contracts from 

utilities and their captive customers. This is not necessarily a bad 

thing, that is just a policy decision California made. 

In addition, a growing problem is that virtually all the existing 

generation left over from the competitive era is barely covering its 

costs or is losing money, yet some of these resources are absolutely 

critical for keeping the lights on in specific locations, for example 

in the San Francisco Bay Area. If one of these remaining competitive units suffers a major mechanical breakdown, it is unclear 

44 

whether any investment would make sense without a guaranteed 

long-term payment from the utilities or the customers just to bring 

the unit back. 

So the lesson learned from California is that half in/half out of 

competitive electricity markets doesn’t work. Once the subsidies 

and bailouts really take hold it kills the competitive part. Investment dries up and long-term ratepayer guarantees are required to 

fund any new infrastructure or even to maintain existing infrastructure. Subsidies beget subsidies would beget more subsidies. So 

this is exactly what we are concerned about happening in the eastern market if we do not address the targeted subsidy issue now. 

The good news is that both PJM and ISO in New England are 

actively engaged on these issues and have developed innovative 

proposals that are intended to allow a state to meet its public policy goals, but act as a firewall to protect the integrity of the wholesale competitive market. Both proposals have significant promise 

and may well result in workable solutions. 

So let me just wrap up by reiterating that competitive wholesale 

markets have produced phenomenal results for benefits for consumers. On the one hand, investment is up and reliability is up. 

On the other hand, prices are down and emissions rates are down. 

So these achievements, however, are in jeopardy due to the desire 

to subsidize or bail out certain generation units. 

The half in/half out competitive market model is unsustainable 

if you move towards the hybrid, so a coordinated effort is needed 

between all the states, FERC, and system operators to develop solutions that allows the states to pursue their public policy goals but 

is done in a way that allows the impact of that to be firewalled off 

from the rest of the wholesale market. Thank you. 

[The prepared statement of Steven Schleimer follows:] 

45 


26883.030

Statement of Steven Schleimer 

Senior Vice President, Government and Regulatory Affairs, Calpine Corporation 

Before the U.S. House of Representatives Committee on Energy and Commerce 

Subcommittee on Energy 

Hearing on "Powering America: Examining the State ofthe Electric Industry through Market Participant 

Perspectives" 

July 18,2017 

Good morning Chairman Upton, Ranking Member Rush and members of the 

Subcommittee. Thank you for inviting me to testify today on the topic of "Powering America: 

Examining the State of the Electric Industry through Market Participant Perspectives." My name 

is Steven Schleimer and I serve as the Senior Vice President of Government and Regulatory Affairs 

of Calpine Corporation ("Calpine"). 

The most important message I can deliver today is that the deregulated markets are working 

and there is no action needed from you. This is not to say that the markets are perfect, but FERC 

and the ISOs have the tools they need to fine tune them. But, more about that later. First, let me 

introduce Calpine, which is an independent power producer ("IPP") that owns more than 26,000 

megawatts (MW) of generation capacity from 80 power plants across the country, and we sell 

wholesale electricity in most of the regional markets, as well as directly to retail customers in 25 

states. Calpine's Geysers plant in California is the largest geothermal power generating facility in 

the United States, which allows us to sell more renewable power than anyone else in the state. 

Importantly, Geysers is a dependable renewable resource that generates 24 hours per day, 365 days 

per year. In addition, within the United States, Calpine is the largest operator of combined heat 

and power facilities, the largest consumer of natural gas in the electricity sector, and through our 

affiliated companies is one of the largest suppliers of electricity to retail (end use) customers. We 

are not a regulated utility receiving a guaranteed return. Rather, we compete against other 

1 
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26883.031

generators and retail suppliers to sell power directly to wholesale and retail customers. So the 

economics of supply and demand are fundamental to our business. 

As a result of our generation and retail customer portfolio, Calpine is actively involved in 

virtually all the regional competitive markets, with a focus on P JM and IS O-NE (hereinafter 

referred to as "East Coast Markets"), CAISO, and ERCOT. Our public policy advocacy in these 

regions rests on two fundamental principles: reliance on markets to provide the most efficient 

outcomes as well as environmental stewardship. In fact, despite our size, Calpine's fleet is 

environmentally the cleanest among the major players in America's IPP sector. 

My two key messages today are: First, the competitive electric sector, in particular the 

East Coast Markets and Texas are successful and functioning well. Significant new resource 

investment is occurring at a pace that is creating an increasingly reliable system, wholesale prices 

arc generally at historic lows, and environmental emissions are down. These new resource 

investments are being made due to the game-changing discovery of shale natural gas, the existence 

of a competitive market with clearly defined rules, and a commitment by the stakeholders to seeing 

the market function. 

Second, the East Coast Markets are now facing serious challenges. Due to various goals 

and pressure from incumbent generators, state policymakers have been increasing their efforts to 

pick winners and losers through out-of-market mandates and subsidies in their respective states. 

If left unchecked, these state efforts threaten the continued viability of competition in these 

regions. A "hybrid" market, where a state relies in part on the competitive wholesale electricity 

market to meet its resource needs, but also retains the right to select and subsidize preferred 

generation resource types to meet certain public policy goals, does not work and destroys all new 

competitive investment. Investors are simply not going to put their money into new infrastructure 

2 
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if they believe their direct competitors will receive out-of-market subsidies. A coordinated effort 

between all the stakeholders, particularly between the states and FERC, is needed to develop 

solutions that allow states to achieve their policy goals while at the same time protecting the 

wholesale market. The good news is efforts are already underway in those regions to address the 

issue. 

Before going deeper into the specific issues, let me first note that the competitive electricity 

markets across the country are different from each other because of varying resource mixes, market 

structures, and policy goals. As a result, the defining issues in the East Coast Markets are different 

than the issues in California, which are different than those in Texas. For this reason, l will spend 

the rest of my time focusing on each region individually, starting with the East Coast. 

The East Coast Competitive Markets Have Been Overwhelmingly Successful Thus Far, but 

There Are Storm Clouds Brewing On the Horizon 

By any measure, the results produced by the East Coast Markets have been a benefit to 

consumer's pocketbooks, to the environment, as well as to the maintenance of a reliable grid. The 

market-driven competitive electric sector is on a transitional path from one supported by older, 

less efficient, and more costly power plants to one support by newer more efficient, less expensive, 

and cleaner natural gas plants. For the Base Residual Auctions in P JM's capacity market occurring 

between 2010-2015, approximately 24,000 MW of new generation were cleared and committed, 

of which 87 percent were natural gas resources. 1 This represents tens of billions of dollars of new 

investment in the region, including a new plant Calpine brought online in Delaware a few years 

ago, and another one currently under construction in Pennsylvania. Concurrent with the expansion 

1 http://www .pjm.com/-/med ia/library/reports-notices/special-reports/20 !60505-resource-investment-incompetitive-markets-paper.ashx 

3 
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of natural gas fired generation capacity, there is also a significant amount of pipeline infrastructure 

occurring in the Northeastern US. For example, since 2014, almost 4 Billion Cubic Feet ("Bcf') 

of new pipeline capacity has been built to export Pennsylvania gas to other states, representing 

investment of more than $2 Billion. Almost 6 Bcfmore is expected to be built between now and 

2021, calling for investment of another $3.5 Billion.2 

In PJM, wholesale prices today are lower in real terms than they were in 2000. Emissions 

are down significantly as well: Between 2005 and 2015, on a pounds of emissions per MWh 

basis, C02 emissions have decreased by 21%, NOx emissions decreased by 70%, and S02 

emissions decreased by 81%.3 At the same time, the grid has become more fuel diverse, not less 

as some claim. In 2005, coal and nuclear represented 55% and 34% of PJM generation, 

respectively, with natural gas at only 5.3%. In 2015, the system was more well balanced and 

diverse, with coal and nuclear each at about 35% market share, and natural gas at approximately 

23%4 Finally, PJM's market enjoys a reserve margin, which is a measure of grid reliability, that 

is significantly higher than its target. 

Similarly, in ISO-NE, wholesale prices dropped 52 percent between 2006 and 2016, and 

are at historic lows since the current competitive market was established.5 Since 2001, regional 

generator air emissions are down as the region shifted away from burning coal and oil to natural 

gas with NO, falling by 68 percent, S02 by 95 percent, and C02 by 24 percent.6 The investment 

in 15,000 MW of new generation, of which 87 percent is natural gas, has been largely responsible 

2 Calpine Company Analysis. FERC aggregated reports. https://www.ferc.gov/industries/gas/indusactlpipelines/approved-projects.asp 

3

http://kleinmanenergy.upenn.edu/paper/electricity-competition 

'Jd. 

5 hltps://www.iso-ne.com/static-assets/documents/20 17/02/20170227 pr 2016 price release.pdf 6 https://www.iso-ne.com/static-assets/documents/20 17/02/2017 reo.pdf 

4 
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for this significant long-term reduction.7 ISO-NE's market also enjoys a reserve margin which is 

significantly higher than its target. 

However, as I noted earlier, due to various goals and pressure from incumbent generators, 

state policymakers have been increasing their efforts to impact the generation mix in their 

respective states. Specific examples include the New York and Illinois "Zero Emissions Credit" 

programs, along with recent attempts to create subsidies for targeted generation units in Ohio and 

Connecticut. In New England, Massachusetts has established aggressive renewable mandates, 

calling for the utilities in the region to issue requests for proposals from certain types of preferred 

resources such as Canadian hydro and offshore wind, and to enter into long-term contracts with 

those resources if authorized by the state regulator. If executed, these contracts will obligate New 

England consumers to spend billions of dollars on high priced renewable generation outside of the 

competitive market structure. While these policy goals may be well intended, they nevertheless 

are having a significant, negative impact on the East Coast Markets. If not addressed, out-ofmarket subsidies will undermine competition, investment will dry up, and these states will be back 

in the business of mandating when, where, and what type of new generation will be built through 

long-term ratepayer guarantees, which is exactly the structure we moved away from several 

decades ago. 

In a very helpful move, FERC recently held a technical conference to provide a forum for 

interested parties to participate and share views on ways to address the impact of state polices on 

the wholesale markets operated by PJM, ISO-NE, as well as NYISO. While many participants 

agreed that recent state actions are threatening the viability of the East Coast Markets, there was 

little agreement on the appropriate path forward to address these actions. Calpine's view is that 

7 https://www.iso-ne.com/aboutlkey-stats/resource-mix 

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FERC and the RTOs must create new market rules that allow a state to meet its public policy goals, 

but at the same time protects the integrity of the wholesale market. The good news is that the 

regional organizations are actively engaged on these issues and have developed market proposals 

that would allow state policy intervention and competitive wholesale markets to exist side by side. 

Both proposals have significant promise and may well result in workable solutions. 

Now I will move on to discuss the California electricity market. 

California Has Moved Away From a Competitive Wholesale Market Model, and the Key Issue 

is How to Compensate Competitive Generators Needed for Ongoing Reliability 

In 1998, California opened its wholesale and retail electricity markets, which prompted 

significant investment in generation by competitive suppliers. However, as a result of the state's 

energy crisis in 2000/2001, as well as the desire to significantly decarbonize the grid, the state 

moved back to a more centrally planned electricity system in the mid-2000's. On the one hand, 

this initiative has been highly successful in bringing resources online-- since that time over 10,000 

MW of conventional gas fired generation has been built, in addition to another approximately 

20,000 MW ofrenewables.8 The state currently has a reserve margin more than twice needed to 

meet its target. The downside is that all this investment is supported by mandate-driven long-term 

contracting programs. These long-term contracting practices have decimated the competitive 

market, and competitive suppliers (who are still dependent on the market for their revenue) are no 

longer willing to make any investment without a guaranteed payment. In addition, since the 

policies that bring about this substantial investment are divorced from competitive wholesale 

markets, it has led to the paradox that while retail rates are amongst the highest in the country as a 

'http://www.couc.ca.gov/uploadedFiles/CPUC Website/Contenl!Utilities and Industries/Energy/Reports and Whit 

e Papers/04 2016 RPS Reoort to the Legislature FINAL.pdf 

6 
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result of these contracting mandates, wholesale prices are so low that the economic viability of the 

remaining generation that is dependent on competitive wholesale markets (generally existing 

conventional generation resources acquired or built when the market was competitive) is 

increasingly threatened. 

To put the issues in context relative to Calpine, in its February 2016 earnings call, Calpine 

presented a graphic which showed that the approximately 3,500 MW of currently uncontracted, 

gas-fired CCGT generation it owns in California produces approximately $20 million offree cash 

flow per ycar. 9 While $20 million may sound like a lot, keep in mind this is relative to an 

unrecovered investment representing several billion dollars, so is actually a very small amount. If 

one of these units suffers a major mechanical breakdown, it is unclear whether anything beyond a 

nominal investment would make sense to bring the unit back into service. 

To be clear, unlike what other companies are pursuing in the Eastern markets, Calpine is 

not seeking a bailout for these resources. In fact, we have already removed one 578 MW facility 

from service, and are scheduled to remove two other peaking facilities at the end of the year. 

Interestingly, the facility Calpine already removed from service was the Sutter Energy Center, an 

efficient combined cycle natural gas fired facility that was the first power plant to come online 

during the summer of 2001, helping to ease California's energy crisis. So, while competitive 

resources are struggling to cover their costs, current CAISO analyses indicate that some of them 

are absolutely critical for maintaining reliability in specific locations. We are urging state 

policymakers to identify which of those resources are needed to maintain reliability, and to apply 

existing mechanisms in the California ISO tariff that provides sufficient compensation to ensure 

the ongoing viability of this critical infrastructure. 

9 http://s2.q4cdn.com/871785789/filesldoc presentations/20 16/CPN-40 15-Eamings-Presentation.pdf 

7 
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Finally, I will cover the Texas electricity market. 

Texas' Market is Fundamentally Working Well, hut Some Improvements are Needed 

Over the last 5 years, wholesale electricity prices have declined by over 13 percent in 

Texas, and are at historic lows. 10 Emissions are down significantly as well. Between 20 I 0 and 

2016, on a pounds of emissions per MWh basis, C02 emissions have decreased by nearly 5 percent, 

NOx emissions have decreased by 24 percent, and S02 emissions are down nearly 40 percent. 11 

Between 2012 and 2016, Texas' competitive wholesale market spurred the construction of more 

than 14,000 MW of new generation, consisting of both wind and natural gas fired resources. 12 

Unlike the East Coast Markets, Texas does not have a capacity market, which is a structure 

in which the grid operator compensates generators for being available to provide power at some 

point in the future. This mechanism creates a forward price that signals to competitive generators 

when and where to invest. Instead, Texas relies on spot energy prices alone to signal the need for 

generation investment. While Calpine believes that a capacity market is a much more efficient 

and reliable structure over the longer term, Texas decided a couple of years ago to stay with its 

current energy-only design. We are confident this decision will be revisited at some point in the 

future. In the meantime, however, the Texas Public Utilities Commission recently opened a 

proceeding to examine improvements to the energy market structure, and we are hopeful changes 

can be made to make the market even more efficient and beneficial for consumers. 

10 https://www. potornaccconorn ics.corn/wp-content/uploads/20 1 7/06/20 16-ERCOT -State-of-the-Market-Report.pdf 11 http://www.ercot.com/rnktinfoiretail/electric 12 Mav 20 17 CDR Report 

8 
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Conclusion 

Competitive wholesale markets have produced phenomenal benefits for consumers. 

Thousands of megawatts of new generation have been built, thus ensuring reliability, and old, 

inefficient generation has retired. Wholesale prices have decreased dramatically over the last 10 

years, and investors, rather than ratepayers, are bearing the economic risk for the success or failure 

of generation facilities. The markets have done exactly what they were intended to do. These 

achievements, however, are in jeopardy. Due to state policymaker actions to subsidize certain 

generation, competition is being threatened. A hybrid model, where the states subsidize some 

generation but leave the remaining generation to rely on the market for their revenue, is 

unsustainable. A coordinated effort is needed between all the states, FERC, and market 

participants to develop solutions that allow states to pursue their policy goals while also protecting 

the wholesale markets. Such an effort will require leadership and a commitment to competitive 

markets, but if we have both, we will be able to develop solutions that ensure the continued 

viability of these markets. 

9 
54 

Mr. UPTON. Thank you. 

Next, we are joined by Jackson Reasor, CEO of Old Dominion 

Electric. Thank you and welcome. 

STATEMENT OF JACKSON REASOR 

Mr. REASOR. Chairman Upton, Ranking Member Rush, and 

members of the Energy Subcommittee, my name is Jack Reasor. I 

am president and CEO of Old Dominion Electric Cooperative in 

Glen Allen, Virginia. Old Dominion is pleased that the Energy Subcommittee is holding this hearing and that we have been invited 

to present our perspective as a wholesale market participant. And 

I must say, Mr. Chairman, I am very proud and pleased to find myself literally in the center of this presentation. 

Old Dominion is a not-for-profit power electric cooperative that 

owns and operates electric generation facilities to provide capacity 

and energy to 11 electric distribution cooperatives throughout Virginia, Maryland, and Delaware. Old Dominion’s members provide 

retail service to end-use consumers and as a result Old Dominion 

has an obligation to serve its consumer owners. 

All of Old Dominion’s members are located within the PJM interconnection. In addition, Old Dominion is a network transmission 

customer of PJM as well as a PJM transmission owner. As mentioned earlier, we have an obligation to serve our consumer members. That means we have to ensure there is enough electricity to 

meet their current and future needs. 

As a participant in PJM, we also have to pay PJM for our share 

of PJM’s cost in procuring capacity to ensure that there is enough 

electricity to satisfy their future energy needs. Unfortunately, our 

experience with PJM’s capacity procurement policies has been 

mixed at best, and let me explain why. 

PJM originally established that we could satisfy the obligation to 

procure capacity by building generation sources or using bilateral 

contracts to obtain capacity at competitive market prices. In other 

words, we could self-supply the capacity obligation. If additional capacity was needed, PJM would procure that capacity and allocate 

the cost to us and the other members and participants within PJM. 

The self-supply, the first option and the PJM procured capacity 

second option, worked well for us. Unfortunately, PJM changed the 

rules and FERC approved the changes. Now our self-supplied capacity might fail to satisfy PJM’s capacity market requirements. As 

a result, we might be required to obtain all of our capacity from 

PJM and pay those associated costs. We could be forced to pay 

twice for capacity, the significant investments and costs associated 

with our self-supplied capacity, plus our share of PJM’s capacity 

costs. 

We believe that federal policy should ensure that long-term investments in generation are honored and encouraged. Specifically, 

we should be allowed to self-supply the capacity procurement obligation as a first option and then turn to PJM’s administered capacity in energy markets as a second option. Federal policy should also 

focus on reliable wholesale service at just and reasonable rates to 

provide the right price signals needed for new generation resource 

development. It would be a mistake for PJM to artificially inflate 

capacity prices above competitive just and reasonable levels. 

55 

In addition, federal policies should foster stability in market designs. The change in PJM’s administered capacity market from its 

original function as a second choice option, a residual market to a 

mandatory market that threatens our first choice option has introduced unnecessary uncertainty which makes long-term planning 

very difficult. 

Finally, federal policy should ensure that choices of generation 

resources are encouraged. PJM’s administered capacity market is 

not a substitute of the wholesale market where we can determine 

the amount, the kind, and the location of generation resources we 

need to meet our consumers’ and customers’ needs. 

Nothing in the law prevents FERC from adopting these needed 

federal policies. Therefore, at this time we do not believe there is 

a need for Congress to enact new legislation giving FERC additional authority or duties. However, the Energy and Commerce 

Committee should continue to use its oversight function and to 

monitor the manner in which the wholesale market operates. 

Thank you, Mr. Chairman. I look forward to answering any questions. 

[The prepared statement of Jackson Reasor follows:] 

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26883.039

Testimony of Jackson Reasor 

President and CEO- Old Dominion Electric Cooperative 

Before the Subcommittee on Energy 

Committee on Energy and Commerce 

U.S. House of Representatives 

"Powering America: Examining the State of Electric Industry through Market 

Participant Perspectives" 

July 18,2017 
57 


26883.040

Summary of Statement of Jackson E. Reasor 

President and CEO 

Old Dominion Electric Cooperative 

• Old Dominion is a not-for-profit power supply electric cooperative that owns and operates 

electric generation facilities that it uses, together with long-term wholesale contracts, to "selfsupply" power to its members. Old Dominion supports competition in wholesale electric 

markets and the ability to self-supply when we determine this is the best long-term resource 

option. 

• PJM's wholesale energy markets arc working reasonably well. Plentiful natural gas supplies 

and improved generation technology have driven down wholesale energy prices. 

• Repeated and significant changes to P JM' s capacity procurement model have raised costs 

and undermined the ability of load-serving entities to self-supply power. 

Federal policies should focus on reliable wholesale service at just and reasonable rates for 

consumers. 

• Federal policies should honor and encourage long-term investments in generation by loadserving entities like Old Dominion. Consumers will fare better if competitive wholesale 

power markets allow load-serving entities to first self-supply the generation capacity they 

need, by building it or purchasing it in voluntary long-term bilateral contracts, and then 

turning to the RTO centralized capacity and energy markets for their residual needs. 

Federal policy should ensure that load-serving entities are able to develop the portfolio of 

generation resources that they believe best meets their needs, based on their economic and 

non-economic criteria. 

• FERC and the RTOs are beginning to address needed reform to these federal policies. 

Congress should monitor this process, but it does not need to amend the Federal Power Act at 

this time. 

2 
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26883.041

My name is Jack Reasor. I am President and CEO of Old Dominion Electric Cooperative 

in Glen Allen, Virginia. Old Dominion is pleased that the Energy Subcommittee is holding this 

hearing and that it has been invited to present its perspective as a wholesale market participant. 

Old Dominion is a not-for-profit power supply electric cooperative, organized and 

existing under the laws of Virginia. Old Dominion provides capacity and energy to eleven 

electric distribution cooperatives in Virginia, Maryland, and Delaware ("Members"). Our 

Members provide retail electric service to end-usc consumers. Old Dominion and its Members 

have obligations to serve their consumer-owners. In the taxonomy of wholesale market 

participants, Old Dominion is a "load-serving entity." 

Old Dominion also owns and operates electric generation facilities that it uses to supply 

power to its Members. This business model, whereby a load-serving entity like an electric 

cooperative also owns generation used to serve its consumer-owners, is sometimes referred to in 

the industry as "self-supply." 

All of our Members are located within the P JM Interconnection, a large regional 

transmission organization (RTO). Old Dominion is a network transmission customer ofPJM as 

well as a PJM Transmission Owner. Unlike most electric cooperatives, however, Old Dominion 

is subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC). 

Old Dominion has long supported federal policies to promote greater competition in 

wholesale electric markets. Old Dominion and other electric cooperatives were among the early 

proponents of unbundled transmission service on the interstate grid. Old Dominion supported 

FERC's Order No. 888, which mandated unbundled, open-access transmission service in 1996. 

Old Dominion welcomed the conversion ofPJM into a regional transmission organization (RTO) 

with a single control area and single tariff, because that would ensure more economical, nondiscriminatory transmission service over the entire P JM region and thus provide more wholesale 

supply alternatives for load-serving entities. 
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26883.042

In short, we support vigorous competition in wholesale electricity markets. We want 

wholesale suppliers to compete for our business, and we want the ability to "self-supply" when 

we determine this resource option is the best long-run alternative. Such competition within the 

wholesale market is good for our Members, and good for the consumer-owners they serve. 

Old Dominion's Perspectives on Current Wholesale Electricity Markets 

In general, the wholesale energy and ancillary-services markets in PJM are working 

reasonably well for Old Dominion and its member cooperatives. The plentiful and inexpensive 

supplies of natural gas that have resulted from technical advances in shale gas drilling 

techniques, coupled with the high efficiency of modern combined-cycle gas generating units, 

have driven down wholesale electric energy prices. And while the resulting lower wholesale 

electric prices may be causing financial hardship for some participants in the industry, this is 

how competitive markets should work. While the PJM energy and ancillary-services markets are 

working well, they are not perfect. We support efforts by PJM and FERC to examine ways to 

improve their efficiency during certain periods. Nonetheless, we should be steadfast by allowing 

these competitive markets to work as designed by permitting them to send the proper signals for 

market exits where appropriate. 

On the other hand, Old Dominion's experience with PJM's capacity procurement 

mechanism, the Reliability Pricing Model, or "RPM," has been mixed at best. This is not a 

market in the usual sense of that word: PJM does not provide an opportunity for willing buyers 

and sellers to enter into voluntary capacity transactions, by which load-serving entities could 

procure the capacity to meet their capacity obligations at competitive market prices. Instead, 

RPM is a complex administrative construct through which PJM procures capacity to ensure 

regional grid reliability on a centralized basis. PJM allocates the resulting costs to load-serving 

entities like Old Dominion. 

4 
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26883.043

FERC initially approved RPM as a residual procurement mechanism for P JM to ensure 

resource adequacy at the least cost. FERC stated that "after [load-serving entities] have had the 

opportunity to procure capacity on their own, it is reasonable for P JM to procure capacity in an 

open auction at a time when further delay in procurement could jeopardize reliability." But it 

added, "This, however, should be a last resort." 1 

The RPM annual capacity auction is still called the "Base Residual Auction." But over 

time, repeated and significant design changes have made RPM more complex and costly and 

have undermined the ability of load-serving entities to use their resources to meet their capacity 

obligations. 

In the ten years since RPM was put in place, it has undergone continuous revisions. 

According to P JM, during the period from 20 I 0 to 2016, there were 24 significant filings at 

FERC to revise RPM, and the 2016 Base Residual Auction was the first such auction with no 

rule changes from the prior year.2 But that is small comfort, because in that prior year, FERC 

approved a complete overhaul of RPM into its current form, "Capacity Performance," which 

imposes onerous performance requirements on capacity resources. These performance 

requirements are simply impossible for some resources to meet and result in costly nonperformance penalties. 3 

Several RPM revisions have involved its Minimum Offer Price Rule, or "MOPR." This 

rule is intended to mitigate buyer-side market power that would lower the auction clearing price 

below an administratively determined competitive price floor. In its original form, the MOPR 

guaranteed that a load-serving entity's self-supplied capacity resource would clear the auction 

1 PJlvf Interconnection, LLC, 117 FERC ~ 61,331 at P 71 (2006). 

http :I !www .pjm.com/-/mcdia/committees-groups/committees/mrc/20 160825/20 160 825-item-07 -pjm-capacityproblem-statement.ashx 

'Pli'vf Interconnection. L.L.C., 151 FERC 1]61,208 (2015), order on reh'g and compliance, 155 FERC 1f61,157 

(2016), aff'd sub nom. Advanced Energy Mgt. Alliance v. FERC, No. 16-1234 (D.C. Cir. June 20, 2017). 

5 
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26883.044

and the load-serving entity would receive auction revenues at the clearing price-even if the 

MOPR prevented that self-supplied capacity from setting the clearing price. In 2011, however, 

FERC approved rule changes that eliminated the guaranteed clearing for self-supplied resources.4 

This meant that a load-serving entity's self-supplied capacity might not clear the auction, and the 

load-serving entity could end up paying twice for capacity-its self-supplied capacity plus its 

share of PJM's capacity costs under RPM. 

In 2013, FERC approved further revisions to the MOPR, including a new, albeit 

imperfect, self-supply exemption.5 But earlier this month-over four years later-a federal court 

vacated and remanded FERC's approval of this new self-supply exemption as well as other 

MOPR revisions.6 This ruling puts a cloud over the results of the Base Residual Auctions and 

leaves the MOPR rules for the 2018 Base Residual Auction in limbo until FERC issues an order 

on remand. 

Given the constant chum of revisions to RPM, and particularly the MOPR, load-serving 

entities like Old Dominion are finding it increasingly difficult to make their own long-term 

procurement plans and to integrate them with RPM. 

Principles for Federal Policies on Wholesale Electricity Markets 

From its experience as an active market participant in PJM, Old Dominion has concluded 

that federal policy governing wholesale electricity markets should reflect several key principles. 

Old Dominion respectfully presents these principles to the subcommittee for its consideration. 

4 PJM Interconnection, LLC, 135 FERC ~ 61,022, order on reh'g, 137 FERC 1f61,145 (2011), order on reh 'g, 138 

FERC 1f61,194 (2012), aff'd sub nom. NJ Bd of Pub. Utils. v. FERC, 744 F.3d 74 (3d Cir. 2014). 

5 PJM interconnection, LLC, 143 FERC ~ 61,090 (2013), order on reh 'g and compliance, 153 FERC 1f61,066 (2015), 

vacated and remanded sub nom. NRG Power Mktg LLCv. FERC, No. 15-1452 (D.C. Cir. July 7, 2017). 

6 NRG Power },4arketing, UC v. FERC, No. 15-1452 (D.C. Cir. July 7, 2017). 

6 
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26883.045

I. Federal policies should focus on reliable wholesale service at just and reasonable rates 

for consumers. 

The bedrock requirement of the Federal Power Act is that wholesale electric rates should 

be just and reasonable.7 Old Dominion believes that federal policy should focus on.ensuring that 

wholesale electricity markets are effective in providing reliable service at just and reasonable 

rates. lfwholesale markets achieve this objective, load-serving entities like Old Dominion will 

be able to meet their service obligations to consumers in the most economical manner. 

A focus on just and reasonable wholesale rates will necessarily involve providing the 

right price signals needed for new generation resource development. Competitive wholesale 

electricity markets provide efficient price signals for market entry and exit. 

Until now, PJM's MOPR has only been applied to capacity bids by new capacity 

resources. Recent proposals to apply the MOPR to existing generation resources would greatly 

exacerbate the problems facing load-serving entities seeking to use self-supplied capacity. 

Moreover, extending the MOPR to existing resources would also transfonn it from a mechanism 

to prevent the exercise of buyer market power into an all-purpose mechanism for artificially 

propping up capacity prices above competitive, just and reasonable levels. 8 

2. Federal policies should ensure that load-serving entities' long-term investments in 

generation are honored and encouraged. 

The key federal policy objective should be to ensure that long-term investments in 

generation resources by load-serving entities are honored and encouraged. Electric power 

generation and transmission is a capital-intensive business. These assets are costly and have long 

operating lives. Planning horizons are long. Accordingly, Old Dominion invests in or procures 

7 16 U.S.C. § 824d(a). 

8 See, e.g., Protest and Request for Rejection or, in the Alternative, Request for Suspension and Further Procedures 

of the PJM Load Group, PJM Power Providers Group v. PJM Interconnection, FERC Docket No. EL1!-20-000 et 

a!. (filed Mar. 4, 2011). 

7 
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26883.046

resources with a view to meet its long-term service obligations to its consumer-owners in a 

reliable and economic manner. 

In our view, consumers will fare better if competitive wholesale power markets allow 

load-serving entities to meet their capacity obligations by first building generation resources or 

procuring them through voluntary long-term bilateral contracts, and then turning to RTOadministered capacity and energy markets for their residual needs. For this reason, it is important 

that RPM be restored to its proper and original role as a residual procurement mechanism--one 

that is subordinate to load-serving entities' long-term investment or procurement of resources to 

self-supply their capacity obligations. 

3. Federal policies should foster stability in market designs. 

Restoring RPM to its original residual function would help achieve another important 

goal-stability of wholesale market designs. The history of RPM's many revisions is a 

cautionary tale. These revisions moved RPM away from its original residual function, but they 

also introduced unnecessary uncertainty for all market participants. This uncertainty makes longrange planning and procurement difficult. Wholesale markets will have to be adapted to 

changing market forces, technologies, and state policies. But the fundamental aspects of 

wholesale market designs should not be in a constant state of flux as they have been over the last 

decade in PJM. Changes to a residual capacity market would be much less disruptive, however, 

since long-term investments and procurement would ensure greater market stability, which is 

their purpose. 

4. Federal policies should ensure that load-serving entities' choices of generation 

resources are honored and encouraged. 

Federal policy should ensure that load-serving entities are able to develop the portfolio of 

generation resources that they believe best meets their needs, based on their economic and non8 
64 


26883.047

economic criteria. Load-serving entities should be free to choose the mix of generation (and nongeneration) technologies that meet their specific needs. 

Centralized capacity markets like RPM will never be able to replicate this complex 

decision-making process. Currently the centralized capacity markets price one generator 

attribute, which is capacity. It may be possible to price other attributes, such as carbon emissions, 

but trying to price multiple state policies soon becomes unworkably complex and inevitably 

controversial. And centralized capacity markets wi!! never become an adequate substitute for a 

true wholesale market where individual load-serving entities determine the amount, the kind, and 

the location of the generation resources they need to reliably and economically meet their service 

obligations. 

Federal policy should ensure that load-serving entities can achieve the resource diversity 

they need. Resource diversity is the primary responsibility of the states. Load-serving entities are 

the primary implementers of state policies. Wholesale electricity markets should not impede state 

resource policies or load-serving entity resource investments or procurement decisions. Instead 

they should provide a non-discriminatory, competitive wholesale market for all types of 

resources. 

Old Dominion's Conclusions and Recommendations 

Fortunately, the RTOs and FERC arc beginning to respond to these salient facts. Market 

forces, technological advances, changing consumer preferences, and changing state policies are 

forcing changes to the organized wholesale markets in P JM and the other eastern RTOs. FERC 

held a technical conference on this subject on May I and 2, 2017.9 Old Dominion participated in 

9 State Policies and Wholesale Markets Operated by ISO New England Inc., New York Independent System Operator, 

Inc., and PJM Interconnection, L.L.C., FERC Docket No. AD17-ll-OOO. 

9 
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26883.048

this technical conference and has filed post-technical conference comments making these same 

points. 10 

Old Dominion appreciates the attention the Energy Subcommittee is giving to these 

important wholesale market issues and the opportunity to present our perspectives. At this time, 

however, we do not believe there is a need for Congress to intervene by amending the Federal 

Power Act to give FERC additional authority or additional duties. 

The Federal Power Act has proven to be a flexible statute over its 80 years of existence. It 

appears RTOs, including PJM, are beginning to address the emerging issues of accommodating 

state policies in wholesale markets, and this process is requiring them to take a close look at 

basic issues of market design. Hopefully FERC will also be able to address these issues. Old 

Dominion believes that there is no one-size-fits-all solution to the many issues now being 

discussed in different states and regions. We believe FERC and Congress should allow for 

regional flexibility in fashioning new policies that meet the basic principles outlined above. 

Above all, Old Dominion believes that Congress should keep load-serving entities and 

their state and local regulators in the driver seat on resource acquisition to power America. 

10 See Pre-Conference Statement of Michael Cocco, FERC Docket No. AD-17-ll-000 (Apr. 25, 2015); Initial 

Comments of Old Dominion Electric Cooperative, FERC Docket No. AD!7-11-000 (June 22, 2015). The transcript 

of the conference and all pre-conference written statements are available at 

https://www. ferc.gov /EventCalendar/EventDetails.aspx?ID=8663&CaiType=%20& Calendar!D= 116&Date=5/l/20 I 

7&View=Listview. 

10 
66 

Mr. UPTON. Thank you very much. 

Tamara Linde, who is the exec VP and general counsel for Public 

Service Enterprise Group, Inc., thank you and welcome. 

STATEMENT OF TAMARA LINDE 

Ms. LINDE. Good morning, Mr. Chairman and Ranking Member. 

Thank you for having me here and thank you to Congressman Pallone for the kind words. My name is Tamara Linde and I am executive vice president and general counsel for Public Service Enterprise Group, or PSEG. 

Thank you for the opportunity to present PSEG’s views on a critical issue facing the electric industry and, by extension, the nation’s electricity customers. The issue is the urgent need to assure 

fuel diversity and resiliency in the nation’s electric generation resource mix and to correct a flaw in the wholesale market design 

that is leading to premature retirement of nuclear baseload generation in our region. 

Let me take a moment to describe PSEG. We are a large diversified energy company headquartered in New Jersey. We employ approximately 13,000 people and our New Jersey utility serves 

around 2.2 million electric customers and 1.8 million gas customers 

across the state. When people talk about an all-of-the-above energy 

portfolio, PSEG is that example. 

Our generation fleet consists of nuclear, natural gas, coal, solar, 

and even some hydro. However, while most of our plants now operate in competitive markets, most were built as part of a state-regulated utility before wholesale markets were created. Nuclear baseload is at risk because the wholesale market has a flaw and does 

not value fuel diversity. In fact, markets were never designed to 

value fuel diversity because they didn’t need to. 

Diversity in generation resources was the status quo when markets were initially designed. The market was designed to drive another important objective which is to deliver the lowest cost resource needed to meet demand. For years, while different fuel costs 

were roughly comparable, markets could drive towards the lowest 

cost without sacrificing fuel security and diversity. Now the shale 

gas revolution has brought opportunity, but it has also revealed 

this serious market design flaw. 

Today, after more than 30 years of operation, the 3,500 megawatt Salem and Hope Creek Nuclear Generating Stations in New 

Jersey turned a dramatic corner last year and they failed to earn 

enough to cover their cost of capital. While we have not announced 

their closure, we have made it clear that they are on an 

unsustainable path. 

Absent a change or intervention, these baseload resources will 

permanently close. In fact, the timeframe for many at-risk plants 

is so short that states are moving forward to address the problem 

before it is too late. We believe that it is our duty to have honest 

discussions with leadership in New Jersey to ensure that the 

stakes are clearly understood and that the state is given an opportunity to take action if it chooses to. 

We believe that state action may be critical if these resources are 

to survive. We believe that these actions can be done in a way that 

does not undermine the integrity of the wholesale market and can 

67 

serve as a bridge until a regional or federal solution takes hold. Ultimately, we do see potential for a market solution. Fuel diversity 

has a value and the loss of fuel diversity has a cost. This needs to 

be factored into the wholesale design. 

Mr. Chairman, this committee has presided over many fights 

within the electric industry over which fuel is better, which fuel is 

subsidized, and which business or regulatory model is best. We understand that you must look beyond winners and losers in the industry and focus on customers, communities, and the nation as a 

whole. 

These closures will impact the reliability and resiliency of our 

electric system, our economy, our competitiveness, our environment, and even our national security. Nuclear energy contributes 

10 billion in federal taxes and 2.2 billion in state taxes each year. 

Our global leadership on nuclear energy drives the adoption of U.S. 

nuclear safety and security standards across the world. A vibrant 

American nuclear industry supports the nuclear supply chain and 

provides the workforce necessary for the defense nuclear industry. 

On a more basic level, it is never a good idea to have all of your 

eggs in one basket. That is true for retirement savings and it is 

equally true for the life-giving electric supply our customers depend 

on. In the past few years, our region has seen a polar vortex, 

Superstorm Sandy, a derecho, an earthquake, and a freak October 

snowstorm. Add to this the prospect for a physical or cyber intrusion or a fuel supply interruption and it is clear that the customer 

interest is better served by not being overly reliant on one fuel 

source. 

Again I want to thank the subcommittee for inviting me today, 

and I will be happy to answer any questions. 

[The prepared statement of Tamara Linde follows:] 

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Tamara Linde, Executive Vice President and General Counsel 

Public Service Enterprise Group 

Subcommittee on Energy 

Committee on Energy and Commerce 

U.S. House of Representatives 

"Powering America: Examining the State ofthe Electric Industry through Market 

Participant Perspectives 

July 18, 2017 

Good morning Chairman Upton, Ranking Member Rush, and members of the subcommittee. 

My name is Tamara Linde, and I am the Executive Vice President and General Counsel of 

Public Service Enterprise Group (PSEG). Thank you for the opportunity to present PSEG's 

views on a critical issue facing the electric industry-- and by extension, our customers. 

That issue is the urgent need to preserve the diversity and resiliency of the nation's electric 

generation resource mix, and in particular, the need to address current flaws in the market 

design that threaten the viability of nuclear baseload generation. 

In the Mid-Atlantic region where PSEG primarily operates, large baseload nuclear plants 

that fueled the economy for decades and are a critical part of the energy infrastructure arc 

quickly becoming uneconomic as a result of a wholesale energy market design that fails to 

adequately value their attributes. The fact is that several nuclear plants in the United States 

have already shut down prematurely and owners of other plants have announced their 

plans to retire. Absent a change or an intervention in the very near future, reliable, much 

needed base load resources that do not contribute to air emissions will permanently close, 

with implications far beyond any single corporate boardroom. 
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Before I elaborate on what is driving this predicament and what might be done to ensure 

that our electric system remains reliable and resilient for the long term, let me introduce 

my company. PSEG is a large, diversified energy company headquartered in Newark, New 

jersey, and is among the largest electric companies in the United States. Our subsidiary 

Public Service Electric and Gas Company (PSE&G) owns and operates electric and natural 

gas distribution and transmission facilities and serves approximately 2.2 million electric 

customers and 1.8 million gas customers in New jersey, many of whom reside in the state's 

most densely populated urban areas. 

Another of our subsidiaries, PSEG Power, owns and operates approximately 11,000 

megawatts of electric generation and sells the output from those generation facilities into 

the regional market known as P)M Interconnection, LLC (PJM), as well as wholesale 

electricity markets in New England and New York. PSEG maintains a diverse and wellbalanced portfolio of electric power generation resources to meet customers' needs, 

including nuclear, natural gas, coal, and solar generation. While we currently are building 

three new natural gas plants in three states, it is worth noting that PSEG planned and built 

its diverse generation portfolio across many decades, and many of the facilities were built 

prior to the advent of competitive wholesale electricity markets. Thus, our belief in the 

importance of fuel diversity to our customers stretches back to the earliest days of our 

company. 
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To return to the problems facing nuclear, the 3,500 megawatt Salem and Hope Creek 

nuclear generating stations in southern New jersey sit on the nation's second largest 

nuclear site and produce about 45 percent of the electricity in New jersey. After more than 

30 years of operation, PSEG's nuclear plants are not earning enough to cover their cost of 

capital. While we have not announced their closure, we have made it clear they are on an 

unsustainable path. 

It may be surprising for Committee members to Jearn that large base load nuclear plants in 

such a well-populated part of the country could be struggling financially. In fact, given the 

favorable location and size of these units, the fact that they are in economic peril may serve 

as a barometer for the severity of the crisis facing the entire nation's nuclear fleet, and the 

urgency facing policymakers who believe, as we do, that our country has something to lose 

with the erosion of fuel diversity and resiliency that would result from the premature 

closure ofbaseload generation, nuclear plants in particular. 

While the economic stress facing PSEG's nuclear plants has a host of aggravating factors 

including significant additional regulatory costs imposed on nuclear plant operators by the 

Nuclear Regulatory Commission over the past 15 years, the proliferation of nondispatchable renewable and demand-side resources enabled through federal and state tax 

policy, renewable portfolio standards and other regulatory treatments such as netmetering, the primary driver is a wholesale electricity market design that fails to 

adequately value and compensate these plants. 
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As for why this is the case, it may be instructive to examine how these markets have 

evolved over time. PSEG has a broad perspective on the evolution of electric wholesale 

markets administered by Regional Transmission Organizations (RTOs) and Independent 

System Operators (ISOs) in the northeast. PSEG has operated in these markets since their 

inception in the 1990s and has been among the original handful of vertically integrated 

utility companies in PJM to champion the movement towards competition in its market. 

We have steadfastly supported the markets to date and actively participated in the 

regulatory and stakeholder processes to improve the markets because of the benefits that 

competition has brought in lowering prices, increasing innovation, and protecting 

customers. Market forces have driven investment in new more efficient generating 

resources and the retirement of older less efficient generating plants. Markets have also 

driven nuclear operators like PSEG to maximize output from nuclear units, making them 

more competitive and more efficient. 

Notwithstanding these benefits, the wholesale market design problem we face now is 

rooted in the historical focus on driving efficiency gains without regard to important 

factors required for the long term reliability of the electricity grid, especially fuel diversity 

and resiliency. This is because competitive markets evolved around a diverse set of 

existing generation resources. In other words, markets weren't designed to drive to fuel 

diversity as an outcome, because fuel diversity in the generation fleet was always 

presumed. 
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Fuel diversity in electric generation was a reasonable expectation in the world prior to the 

shale gas revolution. just as the discovery of near unlimited quantities of accessible natural 

gas has prompted a fundamental re-evalution of our nation's ability to move from energy 

independence to energy dominance, we must also examine the impact of this revolutionary 

development on electricity markets, and make the design changes needed to ensure we 

avoid the irreversible loss of critical infrastructure, including nuclear resources. 

Because time is of the essence for the Salem and Hope Creek stations, in New jersey we 

have begun to discuss with policymakers what is at stake if PSEG's nuclear plants close 

their doors, including the fact that air emissions will increase and the cost of building 

alternative replacement resources will be higher than the cost of preserving the existing 

plants. The economic impact facts are also compelling, with hundreds of millions of dollars 

contributed to the state economy, including 1,600 full time jobs at our plants, and a $30 

million contribution to the local tax base. But far and away the most critical concern we 

have put before state policymakers is the need to ensure the resiliency of electric supply 

against all manner of unforeseen contingencies. If PSEG's nuclear plants were to close, the 

overwhelming majority of remaining generation in New jersey would be natural gas. 

Whether it's a polar vortex, a cyber intrusion, a fuel supply interruption or another event 

we can't imagine today, the utility mantra has always been to have an additional line of 

defense to deal with unexpected events. It's in our DNA to strive to build a system where 

we are not overly reliant on any single facility- or any single fuel source- to ensure the 

availability of the life-giving commodity our customers rely on. 
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The North American Electric Reliability Corporation sums it up by saying that "having a 

portion of a resource fleet with high reliability characteristics, such as low forced and 

maintenance outage rates and low exposure to fuel supply chain issues, is one of the most 

fundamental necessities of a reliable Bulk Power System."1 Nuclear generation covers all of 

these bases. 

Mr. Chairman, the challenges facing PSEG's nuclear plants are not unique. States such as 

Illinois and New York have already acted to prevent premature losses, and others such as 

Ohio, Connecticut and Pennsylvania are considering how they can take steps to prevent the 

premature closure of critical base load generation. These efforts all take different forms, 

but what they have in common is the sense of urgency with which they are being pursued. 

Indeed, given the time constraints facing many of these at-risk plants, and given the 

absence of timely and effective action at the wholesale market level, state action emerges in 

many cases as the only viable option in the short term. We believe state actions can be 

taken in a way that do not disrupt the operation of the competitive markets, but can be a 

bridge until regional or federal solutions take hold. Accordingly we urge the Committee in 

its deliberation on Federal Power Act reform to respect the lawful ability of states to act to 

retain these critical assets. 

In addition, Mr. Chairman, you have done much to encourage FERC to maintain its focus on 

ensuring that the true price of electricity is accurately reflected in the market in order to 

1 Synopsis of NERC Reliability Assessments at page 4, May 9, 2017. 
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support sustained investment, otherwise known as price formation. We applaud you for 

these efforts, and when the FERC returns to a quorum under new leadership we believe it 

will be important for the Commission to tackle this issue with even greater urgency. We 

look forward to working with you and other like-minded members of the Committee to 

continue to emphasize this as a priority. 

Longer term, but equally important is broader reform of the way generation resources are 

valued and priced in the market. We have been encouraged by recent dialogues with 

regional grid operators that suggest the magnitude and urgency of the problem is 

beginning to bring the attention it deserves. FERC should require the RTOs to undertake 

these reforms immediately to ensure that the system is able to provide the diversity of 

resources needed to respond to the vast array of changing conditions, and ensure the bulk 

power system is not just reliable but resilient. More specifically, we need to address energy 

market design, which currently drives supply in a way that disadvantages certain resources 

such as base load generation. 

Finally Mr. Chairman, it bears mentioning that you have brought a diverse panel of 

stakeholders together for this hearing, with varying perspectives and priorities. Over the 

years this Committee has seen a variety of debates within the electric sector over preferred 

business models, fuel types, regulatory constructs and other issues. At the end of the day, 

we understand that you are obligated to look beyond winners and losers among us to find 

the right solutions for the customers and communities you represent, and for the country 

as a whole. 
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We believe that the potential loss of a sizeable percentage of the nation's nuclear fleet 

raises issues well beyond the scope of an individual company or even a specific state. For 

starters, nuclear energy and the technology behind it is one of the great American 

innovation stories. We should give careful consideration to the implications on our global 

competitiveness and our STEM pipeline of losing this primacy. 

Second, these plants have literally been the engines behind local and regional economic 

growth for decades, not just for the electrons they generate but also for the hundreds of 

thousands of well-paying, high-quality jobs, and the funding for schools and police stations 

and local businesses in communities across the country. Nationwide nuclear energy 

contributes $10 billion in federal taxes and $2.2 biB ion in state taxes each year. 

Finally, our nuclear regulatory and operational framework is the envy of the world, and for 

very good reason. It is in our fundamental national security interest to ensure that this 

remains the case. After all, our global leadership drives the adoption of U.S. nuclear safety 

and security standards elsewhere in the world. Similarly, it is in the clear interest of our 

national defense to ensure that our civilian reactors, and the supply chain they support, 

remains robust. It is time to think of the U.S. nuclear supply chain as critical infrastructure, 

just as we regard our national highway system, electric grid and drinking water 

infrastructure. 
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I thank you for the opportunity to share the views of my company this morning, and I 

would be glad to answering any questions you may have. 
77 

Mr. UPTON. Thank you. 

Next, Kenneth Schisler, VP of Regulatory and Government Affairs from EnerNOC, welcome. 

STATEMENT OF KENNETH D. SCHISLER 

Mr. SCHISLER. Thank you, Mr. Chairman and members of the 

committee, for this opportunity to testify. My employer, EnerNOC, 

is an incredible American innovation success story. We were among 

a small group of technology startups right after the turn of the century that pioneered digital applications in U.S. electricity markets, 

and these innovations today are in commercial operation and are 

indeed a vital part of the American economy. 

We do several innovative things at EnerNOC, but today I am 

here to talk about our primary business line and that is known as 

Demand Response. Demand Response is a homegrown American 

technology. It is an innovation that found success here first and 

has quickly spread throughout the developed and developing world. 

The purpose of Demand Response is to engage customers, users, 

and users of electricity to manage consumption of electricity at critical periods when the electricity grid is under stress, to serve as a 

balancing resource on the grid, or to respond to signals when prices 

are high. Demand Response empowers energy users to become 

more flexible with their consumption and to monetize that flexibility providing grid services. 

Companies like EnerNOC are known as aggregators. We aggregate the Demand Response capability of thousands of customers 

and manage them as a portfolio of resources in order to participate 

in electricity markets. Demand Response resources are 

dispatchable in a manner similar to traditional generation resources that receive and respond to dispatch signals from utilities 

and grid operators. In fact, most often Demand Response is actually treated on the supply side of the market, which sounds a bit 

like a non sequitur but it does work. 

We operate in several FERC jurisdictional markets in the U.S. 

as well as several programs under the jurisdiction of state utility 

regulators. Demand Response enjoys broad bipartisan support. In 

fact, Chairman Kelliher seated at the end of the table, as chairman 

of FERC, issued the seminal order that enabled this latent capability of customers to improve the power grid through Demand Response and his legacy was carried forward by his successor Chairman Wellinghoff. 

Demand Response is a win-win. It is unequivocally a win-win for 

the U.S. economy. We contribute to the U.S. energy resource diversity and security supply. It gives system operators one additional 

useful tool to reliably operate the nation’s electricity grid, the users 

of electricity. Demand Response has been credited as helping to 

prevent many major grid emergencies, many major grid emergencies in recent years including many of those my colleague acknowledged, the polar vortex, wildfires in California, and many 

others. 

Customers who participate in Demand Response receive compensation for participation. We pay customers from the market revenues that we receive by bidding their resources again in this portfolio into the wholesale markets. These customer payments of 

78 

course bring down their total cost of energy which makes them 

more competitive in the U.S. and global economy. 

Demand Response is a domestic energy resource, by definition, 

supporting energy independence. Our fuel source, if you will, is 

leveraging the flexibility of our customers to manage their demand 

for the benefit of the grid. Demand Response receives no subsidies, 

no special tax treatment under the federal tax code. It does not 

negatively impact the federal budget and does not require any subsidies from states or ratepayers in order to participate because it 

is cost effective on its own. 

Demand Response improves efficiency of the grid and brings 

down energy costs for all consumers. In fact, in the PJM region Demand Response participation reduced wholesale market costs by 

nearly $10 billion in the current delivery year alone, and this is according to a report prepared by the PJM Independent Market Monitor. These benefits are going to increase as new technologies such 

as energy storage are increasingly adopted as part of a Demand 

Response strategy. 

From a federal policy standpoint, the only prerequisite for Demand Response to thrive is to have nondiscriminatory, open access 

in wholesale electricity markets and that those markets remain 

competitive without pricing distortions. We have come a long way 

in open access, in part thanks to Chairman Kelliher’s order. We 

still have some progress to make. 

As far as healthy competitive markets, we are pleased that 

FERC has recently sought comments on how to maintain competitive markets while respecting the rights of states to create their 

own energy policies. It is vital that we get this right. 

In conclusion, Demand Response is a homegrown U.S. technology. Companies like EnerNOC have revolutionized and created 

tremendous value in U.S. energy markets and we are now exporting that technology all over the world. Our only ask here today is 

that you continue to recognize Demand Response and its importance to the national energy strategy. Thank you. 

[The prepared statement of Kenneth D. Schisler follows:] 

79 


26883.058

Testimony of Kenneth D. Schisler, Vice President of Regulatory Affairs, EnerNOC, Inc., before 

the House Committee on Energy and Commerce, Subcommittee on Energy, Mr. Upton, 

Chairman, July 18, 2017, "Powering America: Examining the State of the Electric Industry 

through Market Participant Perspectives. 

Summary of Testimony: Demand Response in electricity markets is a 21" Century American 

innovation that has improved the U.S. electricity system and is being exported all over the 

world. Demand Response involves coordinated management of consumer demand in a 

portfolio by market agents known as "Aggregators" who are market participants in electricity 

markets, usually bidding as a supply side resource competing against generation. Demand 

Response contributes to energy independence and energy security because it is a domestic 

resource and provides an additional valuable tool for system operators to manage the grid. 

Demand Response participation lowers the cost of energy in the market and allows participant 

to receive direct compensation for making their load management capability a grid resource. 

Demand Response increases reliability and market efficiency, and makes American businesses 

more competitive. Demand Response requires no taxpayer or ratepayer subsidies or tax breaks 

to be successful. Demand Response requires only that it have open and non-discriminatory 

access to compete in power markets and that power markets are truly competitive without 

pricing distortions. 

Thank you Mr. Chairman and Committee Members for the opportunity to testify today. 

My employer EnerNOC is an incredible American innovation success story. We were among a 

small group of U.S. startups right after the turn of the century that pioneered digital 

applications electricity markets and these innovations are now in commercial operation and are 

a vital part of the American economy. 

While we do several things at EnerNOC, I'm here today to discuss our primary business, known 

as Demand Response. Demand Response is a homegrown American technology innovation that 

found success here first, and has quickly spread throughout the developed and developing 

world. 
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26883.059

The purpose of Demand Response is to engage customers to manage consumption of electricity 

at critical periods when the electricity grid is under stress, to serve as a grid balancing resource, 

or to respond to signals during times of high prices. Demand Response empowers energy users 

to become more flexible with their consumption, and to monetize that flexibility providing grid 

services. 

Companies like EnerNOC are known as "Aggregators." We aggregate the Demand Response 

capability of thousands of customers and manage them as a portfolio in order to participate in 

electricity markets. Demand Response resources are dispatchable in a similar manner to 

traditional generation resources that receive and respond to dispatch signals from utilities and 

grid operators. In fact, Demand Response is most often treated in markets as a supply-side 

resource, which sounds a bit like a non sequitur. 

We operate in several FERC jurisdictional markets in the U.S. as well as some programs under 

the jurisdiction of the state utility regulators. Demand Response enjoys broad bipartisan 

support from policy makers and regulators. The Energy Policy Acts of 2005 and 2007 spurred 

adoption of policies that have helped leverage the latent capability of customers to improve the 

power grid through Demand Response. 

Demand Response is a win-win that is unequivocally good for the U.S. economy. 

• We contribute to energy resource diversity and security of supply in the U.S. power 

system. It gives system operators an additional useful tool to reliably operate our 

nation's electric grid. Demand Response has been credited as helping to prevent several 
81 


26883.060

major grid emergencies in recent years. These include the Polar Vortex in the Eastern 

U.S. in 2014, and many others at various times of the year. 

• Customers who participate in Demand Response receive compensation for 

participation. We pay customers out of the market revenues we earn by bidding their 

Demand Response into the wholesale markets. These customer payments reduce total 

energy spend and make American businesses more competitive in the U.S. and global 

economy. 

• Demand Response is a domestic energy resource supporting energy independence. Our 

"fuel source," if you will, is our customer's flexibility to manage demand. 

• Demand Response receives no subsidies or special tax treatment under the federal tax 

code. It does not negatively impact the federal budget and does not require ratepayer 

subsidies because it is cost-effective on its own. 

• Demand Response improves the efficiency of the grid and brings down energy costs for 

all consumers. In fact, in the PJM region of the Eastern U.S., Demand Response 

participation reduced wholesale market costs by nearly $10 Billion dollars in the current 

delivery year alone, according to a report prepared by the PJM market monitor. 

These benefits will increase as resources such as energy storage are increasingly adopted as 

part of a demand response strategy. 

From a federal policy standpoint, the only prerequisite for Demand Response to thrive is to 

have non-discriminatory open access in wholesale electricity markets and that those markets 

remain competitive without pricing distortions. We have come along way on open access and 
82 


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removing market barriers to Demand Response in the last decade, but we still have more 

progress we can make. As far as healthy competitive markets, we are pleased the FERC 

recently sought comments on how to maintain competitive markets while respecting the rights 

of states to create their own energy policy. It is vital that we get this right. 

In conclusion, Demand Response is a homegrown U.S. technology. Companies like EnerNOC 

have revolutionized and created tremendous value in U.S. energy markets and now we are 

exporting this technology all over the world. Our only ask here today is that you continue to 

recognize Demand Response and its importance to our national energy strategy. 
83 

Mr. UPTON. Thank you. 

Last, we are joined by Mr. Glenn, senior VP of State and Federal 

Regulatory Legal Support for Duke Energy, and I welcome you and 

nice to see you. 

STATEMENT OF ALEX GLENN 

Mr. GLENN. As owners and operators of wind farms in Massachusetts, Rhode Island, Pennsylvania, Kansas, Oklahoma, Wisconsin, 

Wyoming, Colorado, Texas, solar farms in California, Arizona, 

Texas, North Carolina, Florida and New Jersey, and battery storage projects in Ohio and one of the nation’s largest in Texas with 

one of our wind farms and in addition to integrated electric utilities 

across seven states, we touch customers across the country every 

single day. 

So to give you a context, Duke Energy is one of the largest energy holding companies in the United States. We have about $130 

billion in assets and we reinvest in our communities $10 billion a 

year, annually, on our electric grid and our gas infrastructure, and 

we provide service to electric and gas customers that represent 

roughly about nine percent of the nation’s population. 

So I would like to use my time today to talk about actions that 

will greatly benefit our customers, unleash innovation, and spur 

economic growth. Specifically, I want to address permitting, renewables policy, cybersecurity, and then too on FERC nominations and 

tax reform. 

Duke Energy plans to invest about $35 billion in addition to that 

$10 billion a year, $35 billion a year over the next 10 years to modernize our system. This transition is underpinned in part by natural gas infrastructure, much of which requires federal permitting. 

Too often we see overlapping and conflicting regulatory requirements which result in higher costs to our customers. 

Bottom line, most permitting regulations impose no timeframes 

within which an agency has to act. And without a reasonable what 

I call a shot clock for decisions, delays put many vital projects at 

risk of completion. So just as our energy system needs to be modernized, so too do our policies. They need to be modernized to reflect today’s markets and encourage innovation. 

As a representative mentioned, the pace of change is increasing 

and so is that complexity, but our regulatory paradigm isn’t. An example of this is PURPA. Today, renewable energy is booming, the 

cost of renewable energy technologies have dropped, and independent power producers are prolific and well financed. Many 

PURPA contracts though are significantly above the market cost of 

power and that is costing our customers money, so updating 

PURPA to reflect current market and technology needs will enable 

utilities to serve our customers at a lower cost. 

Cyber, so hand in hand with critical infrastructure investment is 

the need to protect it. Protecting our infrastructure from 

cyberattacks is a top priority of Duke Energy. The electric industry 

is the only industry critical infrastructure, with mandatory enforceable cybersecurity standards. So Congress could aid our efforts, 

amending the SAFETY Act to expressly include cyberattacks so 

that in the event of such an attack we can focus on what we need 

84 

to do, right, which is get the lights back on and get our economies 

back running. 

Now we can make policy but we also need regulators to implement that policy, so that is where FERC nominations come in. As 

members of this committee are well aware, FERC has been without 

a quorum since February which has prevented action on crucial energy infrastructure projects. The president has now nominated 

three candidates, two of whom are awaiting votes before the full 

Senate and Duke Energy would urge this committee to do whatever 

it can to encourage your Senate colleagues to take up these nominees as quickly as possible so that a quorum can be established. 

Finally, tax reform, although I understand tax reform falls outside the jurisdiction of this committee I mention it because you all 

have a deep understanding and are experts in our business and 

you understand that our industry is unique. Our rates and our returns on capital are set and regulated by state regulators. So because our electricity bills reflect our cost of service, including aftertax cost of capital, we need to preserve interest deductibility. 

So our industry, as a number of the members have mentioned 

here today and our panelists have said, is undergoing remarkable 

transformation. We at Duke Energy stand ready to meet those 

challenges and those opportunities to power our economy to improve the quality of lives of the customers that we serve every day. 

Thank you. 

[The prepared statement of Alex Glenn follows:] 

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Statement of Alex Glenn 

Senior Vice President, State and Federal Regulatory Legal Support 

Duke Energy Corporation 

Before the 

Committee on Energy and Commerce 

Subcommittee on Energy 

U.S. House of Representatives 

On "Powering America: Examining the State of the Electric Industry through 

Market Participant Perspectives" 

July 18,2017 

Good morning, Chairman Upton, Ranking Member Rush and members of the 

subcommittee. My name is Alex Glenn, and I serve as Senior Vice President, State 

and Federal Regulatory Legal Support for Duke Energy Corporation. 

I appreciate the opportunity to provide the subcommittee with the perspective of an 

integrated electric utility, and our view on how we can best serve customers and 

enhance the economies of the communities we serve. Broadly, there are five areas 

where action will greatly benefit the customers we serve. First, establish a 

reasonable "shot clock" for actions on permit applications, as many critical 

infrastructure projects face unnecessary and costly delays. Second, retain the 

federal income tax deduction for interest expense, which helps to keep electricity 

rates as low as possible for customers. Third, update the Public Utility Regulatory 

Policies Act (PURP A) to enable utilities to serve customers at the lowest cost. 

Fourth, move forward on the Federal Energy Regulatory Commission (FERC) 

Commissioner nominees as soon as possible. And lastly, enhance cybersecurity by 

amending the Safety Act to expressly include cyberattacks, and improve the 

process to obtain a security clearance so that we can increase the information 

sharing capabilities between public and private entities. These five actions alone 

would provide substantial- and immediate- value to customers. 

To put my comments in context, it may be helpful to the subcommittee to know 

more about Duke Energy. Duke Energy is one of the largest energy holding 

companies in the United States, with over $130 billion in assets. We are a driver of 

the economies ofthe states in which we operate, investing, on average, $10 billion 

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annually in our energy infrastructure to provide safe, affordable, highly reliable 

and increasingly clean energy to the people and businesses we serve. Our 30,000 

employees take great pride in the work we do 24/7/365, our ranking as the safest 

utility in the industry, as well that we work to keep our rates low relative to 

national averages. We provide electric and natural gas service to 25 million people 

-roughly 9 percent of the nation's population- and tens of thousands of business, 

small and large, across seven states. Our Commercial Renewable Energy business 

unit operates a large and growing portfolio of solar and wind renewable facilities in 

14 states across the United States. We are one of the top five renewable energy 

companies in the country, having invested more than $5 billion in renewables over 

the last decade. 

While the challenges faced by regulated electric utilities like Duke Energy are 

different than those faced by some of the other members of the panel, we all share 

the responsibility of keeping the lights on for the millions of people and businesses 

who rely on us every day. 

The regulatory and legislative decisions made at the state and federal level have 

significant impacts on the lives of our customers, employees, and the many 

communities in which we serve. With this in mind, I would like to offer a few 

thoughts on the challenges before us, and the opportunities for unleashing 

innovation and economic growth. 

Infrastructure 

Investments in a strong and resilient energy system are critical to the nation's 

security, economy and cleaner energy future. In many ways, the energy grid is the 

lifeline of our economy and our way of life. To ensure we are able to continue 

delivering reliable, affordable, and increasingly clean energy that powers our 

economy - and which our customers demand we need to make significant 

investments in modernizing our energy system, making it smarter, and more 

resilient to natural occurrences and premeditated physical attacks and cyberattacks. 

This is particularly important as our economy becomes increasingly dependent 

upon technology. 

The regulated electric utility industry is one of the nation's most capital-intensive, 

investing more than $100 billion annually in critical infrastructure. Duke Energy 

operates the largest energy grid in the country, with more than 300,000 miles of 

transmission and distribution lines to power our communities and the lives of our 

customers. Over and above the $10 billion in annual investments we make to 

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maintain the day-to-day functioning of the grid, we plan to invest another $25 

billion over the next 10 years to modernize our system and build a smarter energy 

future. 

This transition is underpinned by natural gas infrastructure, much of which 

requires federal permitting. There remain challenges, particularly the siting and 

permitting of these vital infrastructure projects to strengthen the power grid. Too 

often, there are overlapping and conflicting requirements that result in higher costs 

for our customers. Most permitting regulations impose no time frame for agency 

action, and without a "shot clock" for decisions, delays put many vital projects at 

risk of completion. The larger the infrastructure projects, which are often measured 

in hundreds of millions of dollars and sometimes multibillion dollars, delays and 

uncertainty can affect the cost of capital and overall project costs ultimately borne 

by our customers. The relicensing of our Catawba-Wateree Hydro project is a 

good example. We submitted our application for a new license in 2006, two years 

before expiration as required by law, and it took more than nine years for the 

federal government to complete its review. 

Tax reform 

Hand and hand with critical infrastructure investment is tax reform. These 

investments are necessary to ensure that customers have safe, reliable and 

affordable energy, but they also create a significant source of high-quality jobs and 

generate local tax revenues in communities across the country. While I understand 

that tax reform falls outside the jurisdiction of this committee, it is worth noting 

here because members of this committee understand that our rates and returns on 

capital investments are highly regulated, unlike that of other businesses, making 

our industry unique. Our distinction from other businesses is evident in our need to 

preserve interest deductibility since our customers' electricity bills reflect our cost 

of service, including after-tax cost of capital. We work hard to achieve the lowest 

cost of capital, and the federal income tax deduction for interest expense helps to 

keep electricity rates as low as possible. 

Unlike other industries, regulated utilities do not benefit from forgoing interest 

deductibility for immediate expensing. We understand why 100 percent expensing 

could stimulate most industries and potentially spur economic growth, but our need 

to preserve interest deductibility is tied to keeping rates low for our customers and 

continuing our significant capital investments across the Southeast and the 

Midwest. 

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Duke Energy supports the goals of comprehensive tax reform and we want to 

partner with you to be the energy company that will power the economic growth 

and expansion throughout the country that will result from a transformation of the 

tax code. 

PURP A Reform 

Just as our energy system needs to be modernized, policies should also be 

modernized to reflect how the electricity sector has changed and encourage 

innovation without burdening customers with unnecessary costs. An example of 

this is the Public Utility Regulatory Policies Act, or PURPA. Enacted in 1978, 

PURP A was intended to encourage increased system reliability and the 

deployment of more energy-efficient and renewable energy production by 

independent power producers at a time when the United States was greatly reliant 

on imported fuel oil. In the years since PURPA was enacted, electricity markets 

have significantly changed. Independent power producers are prolific, wellfinanced and capitalized entities. And many PURP A contracts are significantly 

above the market cost of electricity, which has resulted in customers paying more 

for electricity than they would without such contracts. 

Today, renewable energy is booming and the costs of renewable technologies have 

dropped dramatically. State-of-the-art combined-cycle natural gas generation has 

increased in efficiency to surpass the operating efficiencies of cogeneration 

facilities. The substantial growth in renewable energy due to federal and state 

incentives and policies has made many ofthe requirements ofPURPA 

unnecessary. Accordingly, the original principles and the needs-based application 

of PURP A have been overtaken by dramatic advances in the energy marketplace. 

With these market changes, and the widespread deployment ofPURPA facilities, 

utilities are experiencing operational challenges and higher costs due to PURPA's 

mandatory must-take purchase obligation. Updating PURP A to reflect market and 

technology trends will enable utilities to serve customers at the lowest cost 

possible. 

FERC 

I would like to address briefly the current situation at the Federal Energy 

Regulatory Commission (FERC). As members of this committee are well aware, 

FERC has been without a quorum since February, which has prevented action on 

crucial energy infrastructure projects, including new natural gas pipelines and other 

important rate and policy matters. The electric and natural gas industries depend 

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strongly on a well-functioning FERC. Many of you recognized the seriousness of 

this issue in letters sent to the president in February and March of this year urging 

quick action on FERC nominations. In those letters, committee members and 

leadership acknowledged the importance ofFERC continuing its "important 

regulatory oversight responsibilities to ensure American consumers have access to 

reliable energy." 

The president has now nominated four candidates, two of whom are awaiting votes 

before the full Senate. Duke Energy is increasingly concerned about the lack of a 

quorum at FERC and strongly urges this committee to do whatever it can to 

encourage its Senate colleagues to take up these FERC nominations as quickly as 

possible. 

Cybersecurity 

We are well aware of the recent reports of cyber intrusions into the energy sector 

and certain nuclear facilities. Protecting our infrastructure, operations and 

customer, shareholder and employee information is a top priority for Duke Energy. 

When it comes to cyberthreats and potential breaches at Duke Energy, we work 

diligently to stay ahead of the game, using a "multilayered" defense approach to 

keep our energy grid secure. 

We also work closely with industry and government partners. We have in place 

strong reporting requirements and partnerships to prevent and respond to threats. In 

fact, the electric sector and nuclear sector are the only critical infrastructure sectors 

with mandatory and enforceable cybersecurity standards. Extensive measures to 

safeguard our business and operational networks are necessary to prevent those 

with malicious intent from penetrating our systems, and to ensure we can respond 

appropriately to any security events. 

There are areas Congress can examine to offer immediate improvements: 

First is an examination of third-party liability protections by amending the Safety 

Act to expressly include cyberattacks (with no separate DHS declaration of an act 

of terror) so that in the event of such an attack, utilities can focus on: 1) getting 

the lights back on, 2) rebuilding infrastructures and systems to keep the lights on 

and prevent more harm, and 3) enabling first responders to more effectively and 

efficiently do their critical work- instead of facing the crippling effects of 

protracted lawsuits in multiple jurisdictions. 

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The second area is improving the process to obtain a security clearance so that we 

can improve upon the information sharing capabilities between public and private 

entities. We have a number of individuals seeking clearances, and reducing the 

complexity of extending confidential information to private industry will 

strengthen and increase information sharing. 

Workforce Transformation 

As my remarks today have underscored, the energy sector is going through a 

significant transformation, and the needs and expectations of our customers and 

communities are evolving. We are modernizing our grid over the next decade and 

with that we will need a qualified workforce to meet these demands as we also 

address the challenges of a changing workforce. 

About 30 percent of current Duke Energy employees are eligible for retirement 

today and we anticipate 52 percent of these employees to leave the company over 

the next six years. We anticipate nearly 9 percent of our employees will be leaving 

through retirement and other reasons by 2021. We determined that both the 

changing nature of our business and the scale of our large investments in grid 

modernization are creating a gap in the skills needed to continue to drive our 

business. 

We are working with the Center for Energy Workforce Development to advance 

the awareness of jobs in the energy sector. We are also creating partnerships to 

advance workforce readiness to address the current and anticipated skills shortage 

that we face. Public policy impacting the regulated utilities' workforce training 

programs must also accurately reflect the changing industry needs. Reigniting 

interest in vocational jobs is a key focus for us. Working with secondary 

educational institutions to create curricula and funding for vocational training will 

help accelerate the development and employability of future workers. We are also 

focused on bringing veterans into our workforce. By the end of 2017 we expect 

about 15% of our incoming workforce to be veterans, and last year 50% of our 

lineworker hires were veterans. 65% of veterans pass the pre-employment aptitude 

test required for lineworkers - 17 points above the national average. 

Finally, I would like to compliment the committee on its recent action on used 

nuclear fuel. While outside the jurisdiction of this subcommittee, the strong 

bipartisan vote in favor of Rep. Shimkus' bill shows the ability of this committee 

and its members to show leadership and bipartisanship in an effort to address a 

July 18,2017 6 
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long-standing problem. Our customers have waited a long time to get what they 

have paid for, and we appreciate your efforts on their behalf. 

The pace and complexity of change facing our industry today is unparalleled since 

the battle between AC and DC power in the 1880s. We, as an industry, stand ready 

to meet these challenges while continuing to provide safe, reliable, affordable and 

increasingly clean energy to power our economy and improve the quality of the 

lives of the customers we serve every day. 

Again, thank you for the opportunity to be here today and I look forward to your 

questions. 

July 18,2017 7 
92 

Mr. UPTON. Well, thank you all. And at this point we will reach 

our 5 minutes of Q & A by members of the committee. Thank you 

very much for your testimony, and I would like to hit a couple of 

things in my 5 minutes if I can. One is to talk briefly about baseload closures. We see a lot of that all across the country, but I first 

want to just focus a little bit on the cybersecurity. 

As we visit different installations, whether they be in our districts or states or even around the country, often we are hearing 

that the internet connections of each of those facilities is independent as not, you know, it is hard to penetrate. It is not attached 

to a larger network. Yet at the same time, we read and we have 

had some briefings particularly about state-sponsored attacks that 

are trying to get in, whether it is a water system, whether it is a 

utility, recently some nuclear facilities in the last couple weeks. 

What is it that we can do to make sure that in fact that does 

not happen? What additional tools do we need to put into the toolbox, whether it be FERC, whether it be the Homeland Security and 

others, to make sure that in fact that does not happen? 

And Mr. Glenn, you referenced that just briefly in your testimony, but give us some ideas on where we need to proceed—and 

I don’t know if you have looked at our bill H.R. 3050, Enhancing 

State Energy Security Planning and Emergency Preparedness, but 

that is moving with strong bipartisan support. It came through this 

committee and will be on the floor very soon. 

Mr. GLENN. Thank you, Mr. Chairman. And thank you for that 

bill. I think that is a very, very good start. And I think there is 

a couple of things. One is, we are the only industry with mandatory 

enforceable standards, so FERC and NERC, a delegation of FERC, 

have specifically prescribed standards that we must meet. How we 

meet those standards is a defense-in-depth way of meeting that. 

So there is a couple things. One is, I think, streamlining the 

process by which our background checks for some of our employees 

can be done so that we can work more closely with other government agencies and heads of those agencies. I think that would be 

one thing that we could do that would be supportive. And we would 

be happy to work offline on certain other things that I think we 

can do. 

Mr. UPTON. I just want to assure you—other ideas, other members of the panel, are there additional steps that we should take? 

It is important that we get a quorum on FERC. I think we have 

all been frustrated with the lack of the quorum. I hope the Senate 

acts before they adjourn for sure before their August break. 

Let me talk a little bit about the baseload closures. So again we 

see this. In Michigan we have got a number of coal facilities that 

are beyond their use and they announced that they were closing. 

We have got issues on nuclear facilities around the country and for 

different reasons. We know that natural gas, we know that reliable, renewable energy costs have come down dramatically. 

A number of states like Michigan have actually imposed a new 

standard in terms of a minimum requirement and it is a good thing 

for all of us that support all of the above. But it does take a while 

to get that replacement piece on, whether it is a new gas facility 

or whatever it might be. We all care about diversity, but at the bottom line of course is, I think every one of you mentioned, the cost 

93 

to the consumer of that kilowatt that goes to their home and to 

their business. 

So how do we balance all of that in terms of looking at the future 

and the 21st century energy needs that we have? Ms. Linde, you 

talked a little bit about that and it seems like New Jersey has done 

a really good job. 

Ms. LINDE. Well, thank you. Fuel diversity is really important 

and we are concerned that at the wholesale market level the market design did not take that into consideration. So we do see that 

as something that needs to be addressed, but we recognize it can’t 

be addressed quickly. 

So we have states as was commented on by several of the other 

panelists that have nuclear plants that are suffering that are taking action and doing so as a bridge to a federal solution, it is important that we don’t lose assets that have a long life ahead of 

them and that are providing a low-cost energy to our customers 

every day. 

And I comment on that it is low cost because it is important to 

realize that, while nuclear plants are suffering financially because 

they are not being fully valued in the market, we believe it would 

be more expensive for our customers in New Jersey if they were 

to be retired and replaced with something else. So we believe it is 

less expensive for customers to keep these nuclear plants in operation and to keep them through the rest of their permit life, which 

goes on quite far into the future. 

Our three nuclear plants in New Jersey have licenses that go out 

until 2046, and each of the three plants have different license 

terms but they have long lives ahead of them and they are important for fuel diversity and important for the cost of energy in the 

State of New Jersey. 

Mr. UPTON. My time is expired, but let me, just a quick comment, maybe Mr. Schleimer and then Mr. Kelliher and then we will 

move on. 

Mr. SCHLEIMER. Just really quickly, not necessarily sure I agree 

that the nuclear plants aren’t being fully valued. PJM went 

through a process to revamp its capacity market to value reliability 

even more than it had been previously. 

But putting that aside, I think we generally do agree that to the 

extent that there are issues like fuel diversity or other attributes 

like ramp rates and start-up times and shutdown times, et cetera, 

that aren’t being valued, that that is something perfectly fine and 

acceptable and great for PJM and FERC and the other markets to 

look at expanding what the value of the different services are. 

Mr. UPTON. Mr. Kelliher? 

Mr. KELLIHER. Just very quick. We are really not at a point 

where we are losing diversity. I agree that the competitive markets 

are not designed to achieve diversity, but they have achieved it inadvertently almost. With the competitive markets focused completely on efficiency and cost that has resulted in the retirement 

of the uneconomic units, but in their place has come in very modern, advanced natural gas facilities, solar, and wind. And that result is we have more diversity in our electricity supply today than 

ever before, so there is not really a diversity crisis that we need 

to act on. 

94 

And the concept of baseload is becoming less useful over time. It 

used to be baseload unit was a unit that was cheaper to run. It also 

tended to have, it was operationally inflexible. But the principle 

characteristic, it was cheaper than everything else so you ran that 

first. That has switched. It used to be that coal was cheaper than 

natural gas. That is no longer the case. That is why gas is displacing coal. 

It is not policy, it used to be that the most inefficient coal plant 

could produce electricity cheaper than the most efficient natural 

gas facility, but the fuel prices have switched to the point where 

that doesn’t happen and it probably won’t ever be restored. 

Mr. UPTON. Thank you. The chair would recognize the ranking 

member of the subcommittee, Mr. Rush. 

Mr. RUSH. Well, thank you, Mr. Chairman. 

Ms. Linde, there are many energy consumers who believe that 

climate change is real and must be addressed and that includes the 

overwhelming majority of respected scientists and climatologists, 

the majority of the American people, and the leaders of every country in the world except Nicaragua, Syria, and our own illustrious 

president, Mr. Trump. 

To address this issue especially in absence of federal action, 

many states have developed renewable energy portfolios, including 

Illinois, as I mentioned in my earlier statement, with the objective 

of reducing carbon emissions. In your opinion, would states like Illinois and others who have the objective of reducing carbon emissions be able to hit their targets without nuclear power, and why 

is it important that nuclear plants be valued appropriately as safe, 

reliable, zero-carbon sources of energy? 

Ms. LINDE. Thank you. And you bring up another very important 

attribute of nuclear power. Nuclear power does not emit carbon and 

it is air emission free, so it is very important for an environmental 

policy considering reducing carbon or not increasing the amount of 

carbon. 

I want to comment on something that Joe Kelliher said. We do 

have different opinions on the urgency of this situation, and Illinois 

is one of those states who saw the urgency and the need to take 

action so nuclear plants wouldn’t shut down. In New Jersey, our 

nuclear plants that operate in New Jersey are a large percentage 

of the energy supply. If they shut down we will most likely move 

to predominantly natural gas as the single fuel source with some 

limited renewables. 

New Jersey, like Illinois, has a renewable portfolio standard and 

has made significant steps to increase renewables in the state, and 

my company has been developing a lot of solar in the state as well. 

And we believe that is important. The important message I want 

to leave with you today is that these nuclear plants play a role in 

fuel diversity, they play an important role in keeping prices down, 

and they play an important environmental role and they need to 

be maintained for the future and they are at risk. 

Mr. RUSH. Diversity, how important is fuel diversity in ensuring 

a reliable and resilient grid? 

Ms. LINDE. I could comment on that. NERC issued a study this 

year that highlighted the importance of fuel diversity to a resilient 

grid. I think that report that was issued, I believe, in March of this 

95 

year, does spell out the importance of fuel diversity to resiliency 

and the ability of a system, an electric grid system, to respond to 

a variety of different situations whether weather or physical or 

cyberattacks. 

So we think that fuel diversity as NERC indicated is critical to 

resiliency and long-term reliability. 

Mr. RUSH. Mr. Schisler, I only have a few more seconds here, but 

in your written testimony you state that from a federal policy viewpoint the only prerequisite for Demand Response to thrive is to 

have nondiscriminatory, open access in wholesale electricity market 

and that those markets remain competitive without pricing distortions. 

Moving forward, are you confident that FERC will enact policies 

that will maintain competitive markets while respecting the rights 

of states to create their own energy policy? 

Mr. SCHISLER. When the FERC gets a quorum we will hope that 

that will be the case. I do know that the RTOs and ISOs that you 

will be hearing from next week are taking this issue very seriously. 

We certainly don’t want to stand in the way of states enacting their 

own energy policies, creating their own energy destiny, but market 

participants like EnerNOC, like independent power producers, rely 

upon market revenues and those prices are very important to sending long-term investment signals and that is why they have to be— 

fair, competitive wholesale markets have to be sacrosanct. 

So, FERC has enjoyed a long history, regardless of leadership, of 

trying to trend toward making wholesale markets more competitive 

and I certainly hope that will continue, but that really does need 

to be the guiding principle. 

Mr. UPTON. Thank you. 

Mr. Olson? 

Mr. OLSON. I thank the chair for holding this important hearing 

and welcome to our seven witnesses. It should be no surprise to 

anybody in this room, but my home State of Texas rode down a different trail in terms of our electric grid. Ninety percent is fully 

competitive, run by a group called ERCOT. Two cities, San Antonio 

and Austin, control their local grids. The Panhandle of West Texas 

and East Texas has their grids. They are interlocked. 

Like other states, our source of power is changing rapidly, we are 

shifting from coal power to natural gas power fairly quickly. We 

have two nuclear reactors, nuclear sites, no more coming. That is 

it. We are number one for wind, number one in America with a 

rapidly growing solar industry. 

My question is for you, Mr. Schleimer of Calpine. Your company 

has operations all across the country, many of those in Texas. As 

you mentioned in your opening statement, you said of ERCOT saying they are, ‘‘phenomenal.’’ What does that mean and could our 

markets learn from the Texas example? Could they be phenomenal 

as well? 

Mr. SCHLEIMER. Thank you, Mr. Vice Chairman. 

So yes, Texas indeed did choose a different path. They have almost completely gone complete competition on both the wholesale 

and the retail side. And I would say that you know so far the distinguishing characteristic that you find in Texas versus some of the 

96 

other markets is so far there hasn’t been as much temptation to 

intervene in the competitive markets. 

And so in fact over the last 5 or 6 years or so you have seen 14- 

or 15,000 megawatts of new resource being built, both natural gas 

but a tremendous amount of renewable resources. And those renewable resources actually were not done under long-term contracts with utilities, but really based on confidence in the market. 

We do have some concerns about the structure of the ERCOT 

market just like some of the—it is very different. The U.S. regional 

markets each have their own concerns associated with them because of different policy drivers and dynamics and all that. But I 

would say so far, Texas is, their market remains probably the most 

competitive market with confidence in the rules going forward. 

Mr. OLSON. And how do investment decisions in markets like 

ERCOT that are competitive or like the Mid-Atlantic differ from 

those in more traditional regions? Could a company build a new 

power plant in Texas with the same sorts of return on investment 

like they can in Georgia, for example, any competition issues there? 

Mr. SCHLEIMER. So a company like ours really builds off of what 

the future market looks like and what our expectations of the future market looks like. So in regions where there is a known set 

of rules and we are confident in the set of rules and we can look 

out, obviously we are going to be wrong about what the future 

looks like, but at least we have, if we think we have a fair shot 

of getting our money back. 

In other regions of the country that haven’t deregulated or are 

still vertically integrated where the utilities still dominate, we will 

only make those investments over with the long-term contract or 

with the long-term ratepayer guarantee. 

Mr. OLSON. Thank you. 

Ms. McAlister, ma’am, a new source of energy like wind and 

solar only means something if we can get those to market. In Texas 

we have what is called competitive renewable energy zones, CREZ 

zones, to get resources all across the state. As plants continue to 

close and energy sources shift, new lines will be needed. 

Can you share thoughts about the state of new transmission construction? Is the process working? Is it transparent enough? Are 

there bureaucratic roadblocks? What improvements can be made? 

Ms. MCALISTER. I can speak to the PJM area where most of our 

customers are sited and where we have most of our resources. And 

I think that FERC has orders in place, Order 890, that allow it to 

provide infrastructure through an open and transparent process 

and we think that PJM is doing a pretty good job with the longterm transmission planning for those lines that are needed for reliability. 

But what we are very concerned about is a different category of 

transmission and that is called supplemental transmission. Those 

are projects that are not needed for reliability and essentially the 

transmission owners make those calls whether those lines are 

needed or not and they really don’t have the same transparency 

and open process as what the baseline transmission projects have. 

And so I think probably the best way to balance grid reliability is 

to make sure that the transmission process whether it is for baseline or supplemental is for it to be open and transparent and for 

97 

those Order 890 obligations to apply to all types of transmission 

projects. 

Mr. OLSON. Thank you. And on behalf of the best team in baseball, the best record, the Houston Astros, I yield back. 

Mr. UPTON. Just wait, the Tigers are on a roll. 

The chair would recognize the gentleman from California, Mr. 

McNerney. 

Mr. MCNERNEY. Yes, what about basketball? At any rate, gentlemen. 

Ms. Linde, do you believe that the RTOs and ISOs could charge 

a carbon adder and dispatch in order to adapt to state carbon reduction policies? 

Ms. LINDE. I want to make sure I understand your question. Do 

I think they should or—— 

Mr. MCNERNEY. Could they do that successfully, what effect 

would it have on the market? 

Ms. LINDE. I think the answer is it depends. If the price that is 

added to the market for the carbon adder is an appropriate price, 

then yes, it would make a significant difference and it would enable 

both renewable generation and nuclear generation, their environmental attributes to be valued in the market. 

I caution, however, though, it is important that the details are 

appropriate because we have something else in the region of East 

Coast where it is called the Regional Greenhouse Gas Initiative 

and it was an effort by a group of states to add a carbon value and 

it was too low of a carbon value. 

And in New Jersey we have a gubernatorial election coming up 

this year and both candidates have said that they will rejoin RGGI. 

And I want to be clear to explain that that will not be enough to 

address the nuclear challenge because the price on carbon is just 

far too low. 

Mr. MCNERNEY. Thank you. 

Mr. Glenn, how would increased transmission benefit both clean 

energy development and customers, and what are the biggest challenges to increasing transmission? 

Mr. GLENN. The biggest challenges that we face in increasing 

transmission is the siting, frankly, and that can be at a state level. 

Also if we look at other projects across the nation that go through 

several states, the permitting process, the eminent domain process, 

those are our biggest challenges in getting projects on time, on 

budget, and getting renewable energy resources that have very, 

very low energy costs to markets in which we serve. 

Mr. MCNERNEY. So in your opinion that would benefit the customers and the market to have increased transmission? 

Mr. GLENN. Yes. 

Mr. MCNERNEY. Thank you. 

Mr. Schisler, I have been to a distributed generation facility and 

it is a very interesting process. There is a boom in distributed energy resources, renewables, policies of the Demand Response be 

brought up, and these are coming up pretty quickly. 

Do you believe that the states have been able to make policies 

looking toward long-term effects or have they had to be more reactive? In other words, are states implementing policies proactively 

or are they being reactive to this technology? 

98 

Mr. SCHISLER. I think it has come so quick that they are forced 

to be more reactive. The changing landscape is almost occurring almost at a geometric rate when you look at the cost of storage has 

come down, the cost of renewables has come down. We are seeing 

vehicle-to-grid technologies and what is that going to do? Have we 

reached peak demand? 

Utilities face a degree of radical uncertainty in their planning 

paradigm that they have never had to encounter throughout the 

history of distributed electricity service. And I don’t know that any 

utility or any state commission has really wrapped their arms 

around what does integrated resource planning look like in the future. There is a lot to do in terms of thinking about how do we actually embrace the opportunity with these new technologies while 

addressing this radical uncertainty and still delivering safe, affordable, clean energy to consumers. 

Mr. MCNERNEY. I agree. 

Mr. Schleimer, I believe that you recommended a firewall between subsidized and nonsubsidized generation. Is that the correct 

interpretation? 

Mr. SCHLEIMER. Yes, sir. 

Mr. MCNERNEY. So could you describe what that firewall means? 

What would that look like? 

Mr. SCHLEIMER. Sure. And there is a lot of different variations 

of this, but it basically boils down to running the capacity market 

two times. You run the capacity market once for competitive generators that are not receiving subsidies and that is basically the 

price that they get and so it retains the competitive market price 

and aspect to it, then you run the capacity market again and the 

subsidized units or the units that are getting out of market contracts get the prices out of that second run. 

And so, instead of the subsidization deteriorating prices for the 

entire market, you are basically keeping the competitive market 

prices as they were assuming you didn’t have the subsidization 

coming in. And like I said, there is a handful of different variations 

of that but that is the basic structure. 

Mr. MCNERNEY. Thank you, Mr. Chairman. 

Mr. UPTON. Mr. Walden? 

Mr. WALDEN. Thank you very much, Mr. Chairman. And thanks 

again to our panelists and to the members for participating in this 

important hearing. 

There seems to be some consensus among all the energy stakeholders that the electricity industry is undergoing a period of significant transformation, I don’t think anybody denies that. And if 

just quickly we could go one end to the other, from your individual 

perspectives what do you think are the main drivers of that change 

that are transforming the industry? What are the main drivers? Is 

it consumers? Is it consumer demand, is it state laws, what is it 

that is from your perspective driving it? 

Mr. KELLIHER. Low natural gas prices, lower than expected demand for electricity, and the sharply declining cost of renewables 

both wind and solar. 

Mr. WALDEN. All right. 

99 

Ms. MCALISTER. I would agree it is basic market forces with the 

low natural gas, but I think it is also consumers demanding more 

and wanting different choices in their supply needs. 

Mr. SCHLEIMER. I would agree with that list, cheap gas and wind 

and solar prices coming down. But I would also add that a significant driver is cheap money. I mean there is a lot of private investment occurring in the mid-Atlantic and the Northeast and elsewhere just because, you know, borrowing money is cheap and investors are looking for a place to put their dollars. 

Mr. WALDEN. Get a return. Yes, all right. 

Mr. REASOR. Technology. 

Mr. WALDEN. Expand on that. 

Mr. REASOR. What is brought as lower gas prices, technology, 

changes in the technologies of how we get that gas. 

Mr. WALDEN. Fracking. 

Mr. REASOR. So I would suggest technology has had the largest 

impact and going forward in at least the foreseeable future new 

technologies will continue to have the greatest impact. 

Mr. WALDEN. All right. 

Ms. LINDE. It is a very good question. And the most significant 

impacts that I see are from technology impacting the ability to get 

lower cost gas and that exposing the design flaw that I commented 

on in the wholesale market and also states. States are really driving towards policies that are encouraging and enabling investment 

in renewables and without that I don’t think we would see the level 

of renewable investment that we have at least in my area of the 

country. 

Mr. WALDEN. OK. All right. 

Mr. SCHISLER. I would say technology. Technology has created an 

unprecedented democratization of the grid by users of electricity. 

They can now use energy in different ways and interact with electricity markets and interact with electricity suppliers in ways that 

were not possible even a decade ago and that is going to continue. 

Mr. WALDEN. All right. 

Mr. GLENN. June 19th, 2007, the introduction of the iPhone. 

That has completely changed our business and our business model. 

Customers want convenience, choice, and control over how they use 

and how they reduce our energy. I completely agree with Mr. 

Schisler. That combined with energy storage are the two things 

that have transformed our industry. 

Mr. WALDEN. All right, thank you. 

Mr. Kelliher, you testified that competition has been good for 

consumers as the markets have delivered benefits in the form of 

lower prices. And while competition in the electricity markets always intended to weed out high cost or inefficient generators, we 

now have states favoring policies that would potentially retain 

older, less economically competitive generation for a number of different reasons such as zero-emission benefits, job retention, tax 

base preservation. So were the wholesale electricity markets, were 

they ever intended to incorporate these state and local policies, can 

they and should they? And then I have one other question if we 

have time. 

Mr. KELLIHER. To me, sir? 

Mr. WALDEN. Yes. 

100 

Mr. KELLIHER. They don’t and some critics of competition policy 

fault them for not delivering things they were never intended to deliver, which I think is a little unfair. But your other question is, 

well, can they? That is what RTOs are looking at right now and 

FERC is looking at right now. Is there a way to accommodate, accept state public policy choices with minimal harm to the markets? 

And harm to the markets is going to occur either in the form of 

suppressed prices or the exit of economic generation in lieu of uneconomic generation, so I think there is no way to completely protect the market. It is either going to hurt price or force the retirement of economic units. 

Mr. WALDEN. Well, and as you know, I think it is next week, Mr. 

Chairman, you are going to have the hearing on RTOs and ISOs 

and look at all of that side of this as well. Our goal is to make sure 

we stay ahead of the dynamic changes in the electricity market so 

that the grid works, so you get electricity where you need it when 

you need it. And obviously we have security issues that we will get 

into here and other places, but adequacy is a big part of that and 

the time to build out to make sure we have got the ability to transmit the power where we need it is something this committee is 

very concerned about as well. 

My time has expired, Mr. Chairman. Thank you again. And to 

our panelists, thank you very much for your participation. 

Mr. UPTON. Thank you. 

Mr. Peters? 

Mr. PETERS. Thank you, Mr. Chairman. I want to follow up on 

the Chairman’s questions. But before I let it get away, Ms. Linde, 

what was the price that RGGI charged that you said was too low? 

Ms. LINDE. I am not sure if I have it right here, but it is in the— oh, it is $2.67 per ton of carbon. 

Mr. PETERS. OK, thank you. 

Ms. LINDE. As compared to much higher numbers that are—— 

Mr. PETERS. Thirty to forty is other. So my question had to do 

of just putting aside some very important issues for the minute 

which is cybersecurity, which we talked about, putting aside the 

pricing in the markets, we have seen a phenomenon of this distributed generation. You say it is sometimes driven by consumers who 

want solar panels on their rooves, sometimes it is driven by state 

policies. I am concerned. What I hear about is that that creates an 

issue for delivering electricity, to making sure that when you turn 

on the lights from a systems point of view that they will come on. 

And Mr. Schisler, I think you said something like we haven’t 

started planning for that. What would that plan look like? What 

kind of concerns would you like to raise for us to consider as we 

see these technologies get deployed? 

Mr. SCHISLER. So I think we are talking about two slightly different things. One is sort of a long-term planning paradigm, where 

do we need to transition and what transmission resources and 

what types of resources are we going to need? Are we going to need 

ramping resources or baseload, how much of it? That is more of a 

long view question that regulators have to face. 

It is a fact that we know more today, both grid operators and distribution utilities today know what is happening downstream at 

the grid than they ever have in the past. We have better outage 

101 

management response times. We have better information at what 

is happening at customer sites. And that is, I think that is where 

there has been innovation on that side. Not just innovation on the 

consumer side, it has been innovation on the utility side that has 

made the grid more resilient and I think some of the investments 

that made in recent years in grid resiliency in response to some of 

the storms have helped do that. 

But ultimately I think there is like a real-time component to 

managing real-time operations and then there is the long-term 

view. 

Mr. PETERS. Is that something that the private sector is going to 

handle or is that something that governments need to be involved 

in? 

Mr. SCHISLER. Clearly, the real-time operations, I believe, is 

largely a utility function. So it is the distribution utility and it is 

the wholesale market and that is a regulated function. 

Mr. PETERS. Anyone else have a comment on that? 

Mr. GLENN. Congressman, Alex Glenn. Just to piggyback on 

what Mr. Schisler said, I think, two things. One is, as we invest 

that $35 billion in the grid it is going to make it smarter. It is 

going to deploy new technologies, but it is also going to use data 

analytics. So the last four people that we have hired at our company have been Ph.D.s in data analytics. 

And I think those two things combined are going to help significantly the business that Mr. Schisler is in as well as the ability of 

customers and the ability of distributed generation to propagate 

across our systems in a way that is smartly done. And that is going 

to be the critical aspect of that. 

Mr. PETERS. And I think it has got to be a partnership. So we, 

in San Diego, I think STG needs that 40 percent renewable now, 

and I don’t—that is obviously not rooftop, but that is pretty good. 

But I think that now there is a clamoring among consumers to do 

more rooftop and community choice aggregation and all these 

things. We can’t get so far out in front of it that we are not talking 

to the utilities about making sure that the grid is reliable from a 

supply standpoint. 

And so maybe, Ms. Linde, if you had a question or a comment 

on that I think it is really important to have that conversation and 

to be in partnership. 

Ms. LINDE. Thank you. And I agree with Mr. Schisler that Demand Response is a really critical component of our overall system. 

We want customers to respond to the cost and not use power and 

identify what price they are willing to not use the power. But when 

customers want power, when their rooftop solar is not working because the sun is not out, the utilities are the ones who have to be 

able to meet that demand. 

And it is not just having enough as far as numbers, it is having 

the right mix, the right mix that can respond at the right time in 

the right combination. And the NERC report that came out this 

March addresses that and it identifies all of the different characteristics of different types of supply and how they work together. And 

it is important that we have experts and transmission planners 

and generation planners looking at making sure that when the flip, 

102 

you know, someone flips the switch and they want their power that 

the right mix is standing behind it and ready and able to respond. 

Mr. PETERS. Right. We want to do that in my perspective in a 

way that moves us toward renewables, but we have to do that together. 

So thank you, Mr. Chairman. 

Mr. UPTON. Mr. Shimkus? 

Mr. SHIMKUS. Thank you, Mr. Chairman. It is great to have the 

panel. I think the bigger question now is do we get to the process 

of rewriting the Federal Power Act, really, last codified in 1935. We 

had testimony last year that said well, it was so vague that FERC 

was able to run and help create these regional markets. 

And isn’t the constitutional debate of what is interstate commerce and if you excite an electron and it is going across state 

boundaries that caused the question even maybe the federal regulation of the interstate commerce, which would be the transmission 

portion, and states’ involvement is still in the distribution. 

So I think that is the bigger question, because we are trying to— 

and I am not afraid to be involved in that debate, because as was 

quoted by Mr. Schisler, we have democratized this electricity use 

to the individual. And the iPhone was, Mr. Glenn, you used the 

iPhone as an example. So, and Joe was here when we did competition, when we used to have state regulated markets and we moved 

to the regions. 

But I want to spend my time—and the RTOs will be here next 

week, but the people who have complaints about the RTOs will not 

be here next week. And so I really want to focus on two comments 

that are really the same, Mr. Reasor and Ms. McAlister—Mr. 

Reasor, you have a beef with PJM and you are wholly contained, 

OK, you are the rural cooperative, a different model evolved over 

time and some would say obviously it is a not-for-profit entity. 

So briefly can you say, what is your beef? Because then I am 

going to go to Ms. McAlister—at least Illinois Municipal Electric 

Association has a beef because they are in two RTOs which causes 

problems. So first of all, what beef do you have with PJM because 

you are wholly contained, and then I am going to move to Ms. 

McAlister to explain the separation. 

Mr. REASOR. Thank you, Congressman. Our big issue is the ability and having the first option that we can self-supply. 

Mr. SHIMKUS. And you said that about 15 times in your opening 

statement. 

Mr. REASOR. I did. I hope you remember that. 

Mr. SHIMKUS. So what do you mean by self-supply? 

Mr. REASOR. We are a load serving entity. That is what makes 

us a little bit different than some other parties. 

Mr. SHIMKUS. So you are owners and the Federal Power Act 

gives you the authority, in fact it is in the statute that you can selfsupply. 

Mr. REASOR. Basically that is what we would argue. 

Mr. SHIMKUS. Under 217(b). 

Mr. REASOR. That is correct. Because we are a load serving entity we have an obligation to meet the needs of the consumers that 

own us, which we would suggest, I realize it is a different model, 

103 

but we would suggest is the ideal model of a nonprofit entity that 

the consumer owns and that is where they get their electricity. 

We should have the opportunity to self-supply that load to—— 

Mr. SHIMKUS. You should have the opportunity, it is in the statute. 

Mr. REASOR. Well, but PJM in the way that—— 

Mr. SHIMKUS. Well, that is my point. 

Mr. REASOR. Yes. And as you said, I have a little bit of a beef 

with PJM. However, I would say to you that when PJM started 

their first option for us to meet their capacity obligations, which 

are legitimate, was that we could look first to our self-supply. 

Mr. SHIMKUS. OK, let me go to Ms. McAlister. I am running out 

of time. Because I hope, we haven’t scheduled this out but I hope 

you know where I am going with this question. 

Ms. MCALISTER. I think I do. And thank you for the question and 

just a quick point. We are also in two RTOs and we also serve load 

in non-RTO areas, so we have kind of got the whole scheme of 

things. So we have got the same kind of beef that Old Dominion 

has and, really, the crux of the problem from our perspective is 

that the capacity market and PJM over time has evolved and become overly complex. 

It also reduces the amount of resources, the types of resources 

that can participate because they no longer meet the definition of 

a capacity resource and it has just become so unduly complicated 

that it makes long-term planning for entities like us very difficult. 

And we are at risk with what is called the minimum offer price 

rule which is essentially a floor price that is administratively set 

by PJM that makes—— 

Mr. SHIMKUS. And let me hold you because my time is running 

out and I want to get this point out—— 

Ms. MCALISTER. Yes. 

Mr. SHIMKUS [continuing]. Is that so in Illinois we have PJM and 

we have MISO. Most of our generation is in the south from our Illinois municipal or even our co-ops. They should by federal law be 

able to provide to part of their ownership up to the PJM. But because of these regions, part of that load is sold to PJM who sells 

it back into their market at a premium versus the original clearing 

price in MISO, which means that those people who are owners of 

the generation can’t get the real price of the generation. 

And I think that needs to be looked at and I yield back, thank 

you. 

Ms. MCALISTER. Do I get to respond? 

Mr. UPTON. The gentleman’s time has expired. 

Mr. Green? 

Mr. GREEN. Thank you, Mr. Chairman. I want to welcome our 

panel and thank the chair and the ranking member for calling it. 

I was just kind of reminiscing because I have been on the Energy 

subcommittee and I look back in 2001 and ’02 when we had so 

many different problems that are—in the day we have some problems that we can actually deal with, back then it was almost intractable. But again coming from Texas we don’t want anybody 

messing with us and we will fix our own problems through our regulatory commission. So we have a different problem today, obviously availability and cost and that is affecting everyone. 

104 

Mr. Kelliher, you touched on how significant changes in the 

breakdown of our nation’s electricity markets have led to questions 

about the driving force behind the retirement of certain types of 

electricity generation, market fundamentals or policy on the state 

or federal level. You stated the preponderance of the evidence suggests that market factors are the primary driving force behind the 

retirement of uneconomic generation methods. 

Can you elaborate on the evidence you reference when stating 

that the market forces rather than a regulatory process has been 

the primary driving force behind the retirement, and again both 

your experience on this committee as a staff member but also in 

the industry. 

Mr. KELLIHER. There have been arguments from time to time 

that negative pricing by wind is causing retirements of nuclear and 

coal plants, and there is pretty, I think very persuasive evidence 

that that is not true. There is PJM analysis that shows that first 

of all, negative pricing is when you bid below zero, but wind 

projects do bid negative from time to time, so do nuclear plants, so 

do hydro projects. So negative pricing is not something that is particular to wind projects. 

But if you look at, well, when does negative pricing by wind 

projects set the market price in one of the RTOs, PJM analysis 

shows that it occurs 0.1 percent of the time, so that is 1 hour out 

of every 1,000 hours. I think it is hard to say that therefore that 

wind is the villain. 

Mr. GREEN. Right, they are not driving the train. 

Mr. KELLIHER. Right. And then even in Texas, your State of 

Texas where there is much more wind penetration in Texas than 

in PJM, negative pricing by wind projects in Texas occurs less than 

one percent of ours. So I think that shows that federal policies that 

encourage wind development are not causing those retirements. 

And then the coal plant retirements, that is driven by in most 

cases just pure cost factors. As I said earlier, an uneconomic, an 

inefficient coal project used to be able to deliver power cheaper 

than the most efficient gas project. Those fuels have reversed themselves and now efficient gas projects will always be able to produce 

cheaper than even more efficient coal projects. 

So I think coal retirements are really driven primarily by economics, not by environmental regulation. There are some that environmental regulation has been the tipping point where the cost of 

complying with new requirements, arguably, is the tipping point 

for some coal projects. 

Mr. GREEN. Thank you. 

Mr. Chairman, well, again I have welcomed Calpine to Texas 

over the last 15 or 20 years, and I joked at one ribbon cutting for 

a cogen facility in our district and said, when are you going to 

change your name to Texpine because so much of your investments 

are in Texas? But I appreciate you being part of our market. My 

Californians love that. 

I am pleased that you discussed committed method of the energy 

market in Texas spurring increased investment and renewal in 

natural gas resources. You mentioned how these investments not 

only lead to lower prices for consumers but also increase in the 

electrical system reliability and decrease emission rates. 

105 

And let me point out in your statement where you talk about the 

Texas market, over the last 5 years electricity prices declined by 

over 13 percent in Texas and historic lows. Emissions are down 

also. Between 2010 and ’16, the emissions per million kilowatt 

CO2s were down 5 percent, NOx emission and CO2, SO2 emissions 

were down. NOx was down 24 percent and SO2 were down 40 percent. 

I can’t remember in my history of being an elected official, 

whether it be in the Texas in the legislature or here, I have seen 

that kind of result in the electricity market. Can you share any 

other information outside of what your testimony was? 

Mr. SCHLEIMER. Well, that has really been driven by, like we 

talked about earlier, the low gas price environment and a tremendous amount of investment that has been spurred in the Texas 

market in both highly efficient natural gas-fired combined cycles as 

well as, as you know there is a tremendous amount of wind in 

West Texas and that has largely displaced a lot of the coal and old 

steam facilities that the utilities used. Those coal plants in Texas, 

a lot of them are in financial difficulties now as a result of the 

change-out in the technologies. 

Mr. GREEN. Well, Mr. Chairman, thank you for calling the hearing. Again, thank all our witnesses, because again it is good for us 

to look at where we are today as compared to where we were 5, 

10, even 15, 20 years ago. Thank you. 

Mr. UPTON. The chair would recognize in perfect segue the gentleman from Texas, Mr. Barton. 

Mr. BARTON. Thank you, Mr. Chairman, and I will be brief. I 

have to go to a lunch meeting. 

This is an important hearing, but I don’t think it will make the 

front pages. There is a probably a better probability of the latest 

Trump tweet being on the front page tomorrow than anything we 

discover here. 

But this is an important hearing, Mr. Chairman, because of a 

small thing called reliability. I will tell you what reliability is. I 

went out to my car this morning to attend Chairman Walden’s 

breakfast meeting with the subcommittee chairman. When I turned 

the key nothing happened. I had no reliability. As it turns out my 

alternator had conked out. It worked yesterday, but it didn’t work 

this morning. By the same token, when the people that are putting 

this hearing together, the staff getting ready for the hearing, when 

they came in this morning they turned the switch, the lights came 

on. 

Our electric grid has got about 100 percent reliability. But that 

is not a given that it will always be so, and as we retire more and 

more plants and more and more of our generation is from renewables, there is nothing wrong with renewables except sometimes 

the wind doesn’t blow and of course sometimes there is no sunshine. Water power is pretty much there all the time. 

So we need to really think about better ways to continue to 

maintain and if possible improve reliability. One of the ideas that 

has been circulating is this idea of using artificial intelligence. Of 

course I know most people think that is what the Congress has is 

artificial intelligence, but this is a different definition. 

106 

So I would like the panel to comment on if they think that this 

concept of artificial intelligence can be used to more predict where 

the demand is going to be and help allocate the supply to the demand so that we maintain as close as possibly 100 percent reliability, so any comments from anybody about artificial intelligence 

used in the electricity grid? It is not a trick question. 

Mr. GLENN. Congressman Barton, this is Alex Glenn from Duke 

Energy. I think that is going to be your next significant plateau 

then in technology improvements. 

Mr. BARTON. So you think it can be used? 

Mr. GLENN. I think it can be used and I think it ultimately will 

be used, the question is how and when. And I think what you are 

going to see is baby steps to look at it. And you might see it in call 

centers first, so that there is artificial intelligence in all of our call 

centers, and you may see that ramped up in different aspects. 

Mr. BARTON. Is your company working on—— 

Mr. GLENN. We are working on that now to do that. So I think 

as you see technology and the pace and rapidity of that technology 

improvements you are going to see that continue to be more ubiquitous as the years progress. 

Mr. BARTON. That is a nice word, ubiquitous. I will look that up. 

Sounds good though. 

Yes, ma’am? 

Ms. LINDE. I would also add at PSEG we are constantly adding 

new technology to a variety of our generation facilities, to project 

what piece of equipment in that generation facility might have a 

fault. We just actually upgraded some of our technology to have 

more predictive information, because the lights need to be on when 

people flip the switch. So our focus is making sure that our facilities, there are no surprises. 

Also in understanding the transmission system, there is greater 

and greater intelligence being added to the transmission system to 

tell us information before it becomes a problem. And I agree with 

Mr. Glenn that I think we are going to be seeing more and more 

of this and utilities are paying attention. The industry is paying attention to this. 

We also have to manage cost, so it is a balance between adding 

the right amount of technology but not doing it in a way that burdens customers if there is not a tremendous value. So it constantly 

has to be weighed to make sure we are putting the right intelligence into the—— 

Mr. BARTON. My time is about to expire. Is there anybody that 

doesn’t think artificial intelligence is an option as we try to maintain reliability? 

Mr. REASOR. Congressman, I would just say that I am not going 

to say it isn’t. I think it is important for these reasons that have 

been stated to help us better understand where the needs are and 

the equipment and technology. But remember, the old non-artificial 

intelligence tells you that for good reliability you have to have the 

generation and you have to have the transmission to get it there. 

The artificial intelligence maybe can tell us where it is lacking 

and maybe can tell us what equipment is failing, but it doesn’t generate electricity. And ultimately for real reliability, true reliability 

107 

you have to have the generation and you have to have the transmission to get it there. 

Mr. BARTON. I eat a lot of health food but I also eat a lot of meat 

and potatoes, so I understand. With that I yield back, Mr. Chairman. 

Mr. OLSON. [Presiding.] The gentleman yields back. The chair 

calls upon the gentlelady from Florida, Ms. Castor, for 5 minutes. 

Ms. CASTOR. Thank you, Mr. Chairman. And thank you to all the 

witnesses that are here today. Congress doesn’t do a very good job 

thinking decades ahead and planning ahead, it is always the next 

budget battle or the next bill on the horizon. 

But coming from Florida, I am very attuned to the rising costs 

for consumers and all of us due to the changing climate, a/c bills 

and flood insurance, and Mr. Glenn knows in our neck of the 

woods, beach renourishment to keep our tourism economy going, 

what we have to do with property taxes to retrofit a lot of water 

and waste water infrastructure, property insurance. 

So it seems to me we have reached a point where the old business model of selling electricity needs some updating and some 

places in the country are doing that better than others. The old 

business model was sell as much power and generate as much as 

possible to make your profit build plants and there are incentives 

for that. 

But that doesn’t really match up with what we need to do to promote a better mix. Yes, the baseload and reliability are fundamental, but we have got to do a better job in planning for the future and incentivizing the demand response, energy efficiency, conservation, and the transition to renewables. 

Tell me what is working best out there across the country when 

it comes to those kind of incentives for you all, what you all believe 

can be the answer. Now realizing that we have had a change and 

the Clean Power Plan isn’t going to be pushing everyone in all of 

the states, but what is working? What are the best incentives for 

our utilities to help us with the future? 

Ms. MCALISTER. Thank you for the question. I think largely what 

you are talking about the shifts in resources are really being driven 

by consumer demand. And part of what we think would be a good 

incentive is allowing those resources to actually participate in the 

market without restrictions and be on par with some of the other 

types of supply, so that—— 

Ms. CASTOR. What do you mean? 

Ms. MCALISTER. Well, for example, in the PJM capacity construct 

it has become more rigid and it has become less flexible and it 

doesn’t incorporate some of the renewables because they can’t operate 24/7 the way that some of the old coal-fired units can participate. 

Ms. CASTOR. Is there a particular state or region in the country 

that is doing that better than others? Is there something specific 

you can point to? 

Ms. MCALISTER. I know at AMP in the Midwest we are at 21 percent renewable resources, which for a Midwest utility is rather 

high, and that is because we are responsive to the consumer demands. We are a member—— 

108 

Ms. CASTOR. Is it consumer demand or has the states set energy 

efficiency goals, conservation goals, or renewable goals? 

Ms. MCALISTER. For us it is not the state because we are not regulated by the states, we are locally regulated. So it is the consumer 

driving the demand. 

Ms. CASTOR. Mr. Peters and I were comparing notes. What did 

you say the San Diego area or—what is it? 

Mr. PETERS. Forty. 

Ms. CASTOR. With renewable, based on renewable power. And 

what is the state of California? 

Mr. PETERS. Thirty-three. 

Ms. CASTOR. Thirty-three. And that is because—will you be my 

witness, because the state has set those goals. 

Mr. PETERS. Well, certainly it is partly because the state has set 

renewable goals and it is partly because I think the consumers are 

clamoring for it as well. 

Mr. SCHISLER. I would say one thing that is working well is 

many states—California, Texas, and actually there is too many 

probably to list now—are doing a good job of getting customer data 

to customers through their smart grid investments and that is empowering customers and opening up newer and more efficient ways 

to use energy. So that is one example of what is working well and 

should be replicated elsewhere. 

Ms. CASTOR. I guess there was some discussion of cell phones 

earlier, and this, the Millennial generation they are ready, and I 

do hear too the consumers are clamoring for more control now. Person-to-person maybe that doesn’t make a dent, but you empower 

consumers and work with your industrial users over time and use 

technology and it kind of highlights the need for greater infrastructure investment if we could ever get the Congress in a bipartisan 

way to move on to energy or to infrastructure investments. 

And I know, Mr. Glenn, you talked about this. We have got to 

make sure that energy resiliency and that we do an infrastructure 

bill it isn’t just the bricks and mortar for transportation. It is very 

important, but it has got to be our energy future to help us control 

the costs that I see on the horizon decades ahead. 

So thank you, Mr. Chairman. I have run out of time, I yield 

back. 

Mr. OLSON. The gentlelady yields back. The chair calls upon the 

gentleman from West Virginia, Mr. McKinley, for 5 minutes. 

Mr. MCKINLEY. Thank you, Mr. Chairman. 

When we put two issues on the table, both the grid reliability 

and the greenhouse gases and climate change or all those combined, it is hard to extract good policy, good public policy and how 

we might be able to address that because there are consequences 

involved with those decisions and how that works out. 

For me in West Virginia it is different than it is in California or 

Texas or elsewhere, is we have seen the impact of the regulatory 

impact over the last 8 years. Example, in West Virginia we used 

to have just in 2008, we had the second lowest utility bills in the 

country for industrial consumption, now we are 26th because our 

coal-fired power plants many of them were shut down or they were 

required to upgrade their facilities to such a level. 

109 

Now in conjunction with that at that same time, we had the seventh best rate of unemployment in the country, now West Virginia 

is 49th. So there are consequences to these. We have got to understand when we debate these issues we are all sensitive that there 

are consequences with it. And I don’t understand yet, I have not 

been able to find a good response back for the coal miners across 

this country, but particularly in West Virginia, what did they do 

to cause this? Why is it they are losing their jobs? Why are there 

bankruptcies involving them? We have got to be more sensitive to 

the individuals when we set policy here that they are going to lose 

their jobs. 

So Ms. Linde, if I could ask you a question. If we leveled the 

playing field and got rid of these tax subsidies that sweep all across 

our utilities could the traditional baseload power generators be better able to compete? 

Ms. LINDE. Thank you. The PSEG is not, certainly is not encouraging the extension of those credits, but I also want to be clear that 

the existence of those credits are not what is causing our nuclear 

plants to be at risk. It is an aggravating factor perhaps but certainly not the main driver. The main driver is that there are fuel 

diversity and there are environmental attributes which some people also value are not being valued right now in the marketplace. 

Mr. MCKINLEY. And that is why I wanted to get to that point, 

because you mentioned that several times, your main driver. So my 

question to you would be, you talked about the main driver or the 

economic stress on base plants and you mentioned nuclear in particular, because I think that is a solid baseload provider as is coal, 

is that the market fails to adequately value and compensate baseload. 

Ms. LINDE. It does. There is—— 

Mr. MCKINLEY. So shouldn’t we do something about that? 

Shouldn’t we—again, my next—is in the market value, reliability, 

and resiliency, but we are not. 

Ms. LINDE. We are not currently in the competitive marketplace. 

And it is not because there is an intention not to do it, it is just 

the market wasn’t designed to do it. And we are pointing that out 

that—and for policy makers to make decisions. And we are pointing it out to you today, and we hope that the policy direction given 

to FERC is that fuel diversity and resiliency is important and we 

hope that that direction will cause changes and fill that gap in the 

market. 

But we are also pointing it out to New Jersey, because states 

have an important role here. Some states like Illinois and New 

York have already taken action. They are not waiting because once 

these plants shut down they are gone forever. They are closed permanently, and we don’t think that is good public policy. 

So our ask is to recognize that these plants without a change either from the state or the federal government or some change in 

the price of natural gas which is certainly outside all of our control, 

that without some change these plants, we will see a shutdown, a 

continued and regular shutdown of these plants until it is too late 

and we shouldn’t let that happen without deciding that we 

want—— 

110 

Mr. MCKINLEY. And if I could, rather than allow this to go back 

up to 30,000 feet, what are specifics? Can you provide me or this 

committee some specifics of how we might be able to address the 

reliability and value that in our cost base? 

Ms. LINDE. Absolutely. And we can do that separately outside of 

this committee, but FERC has been looking at this issue. The DOE 

as was commented before is working on a report. I think both of 

those places, FERC through their proceeding and the DOE through 

their report, those are vehicles to identify fuel diversity and resiliency as an important public policy because it is a choice that is 

going to be made. 

Mr. MCKINLEY. Thank you. I yield back my time. 

Mr. OLSON. The gentleman’s time has expired. The chair calls 

upon the gentleman from New York, Mr. Tonko, for 5 minutes. 

Mr. TONKO. Thank you, Mr. Chair. There has been some talk 

about that diversity that assists the whole equation here. And 

while I am sure there are differing views on how it should be done, 

do witnesses agree that it is important to maintain a diverse fuel 

supply for the sake of reliability? Maybe go across the board starting to our left here. 

Mr. KELLIHER. In general, yes, but we have diversity now not because it was a goal, it is a byproduct of building the next increment 

of supply is looking for the technology that is lowest cost at the 

time and these tend to be long-lived facilities, so it is not as if in 

1960 we had a certain electricity supply pie we planned to. I would 

say in general, yes. 

Mr. TONKO. OK. 

Mr. KELLIHER. In general, yes. 

Mr. TONKO. If we would just go across the board and just give 

us a specific yes or no. Thank you. 

Ms. MCALISTER. Yes. Grid reliability is crucial and fuel diversity 

is one aspect of that. 

Mr. TONKO. OK. 

Mr. SCHLEIMER. I would agree with that that fuel diversity is 

crucial but it is not single dimensional. You can’t say one fuel, you 

looked at one fuel versus another and it is more fuel diverse. You 

have to look at flexibility, startup times, shutdown times, ability to 

integrate renewables, so there is eight or nine dimensions to fuel 

diversity, but absolutely. 

Mr. TONKO. OK. 

Mr. REASOR. Diversity is always good. You just have to be careful 

that you don’t start regulating and controlling diversity and create 

winners and losers. That is a very risky slope to go down. 

Mr. TONKO. Ms. Linde? 

Ms. LINDE. I think you know my answer that fuel diversity is important. 

Mr. TONKO. We heard you. 

Ms. LINDE. And it can be a public policy without creating winners and losers. A fuel diversity doesn’t mean nuclear for everyone. 

In some places nuclear doesn’t exist. In New Jersey, fuel diversity 

means nuclear continues at least for the life of the licenses that 

they have. 

Mr. TONKO. Thank you. 

Mr. Schisler? 

111 

Mr. SCHISLER. Of course fuel diversity is good, but I do worry 

that we go down a path of sort of central planning and picking winners and losers which is ultimately going to lead to inefficiency. So 

fuel diversity is good, but I think we need to use market forces to 

achieve it as far as possible. 

Mr. TONKO. OK. 

And Mr. Glenn? 

Mr. GLENN. Yes. 

Mr. TONKO. OK, thank you very much. 

Ms. McAlister, do you believe the RTO operated markets have 

provided the proper signals for a diverse array of electricity resources? 

Ms. MCALISTER. I do not. That is really not what they were designed for as we have talked about a number of times. They were 

really designed for least-cost dispatch and that is what they are 

achieving, but they are not providing incentives for diverse fuel 

sources. 

Mr. TONKO. And again across the board, what would the reaction 

be to that about the RTOs? 

Mr. KELLIHER. They were not designed to achieve a certain level 

of fuel diversity, no. 

Mr. TONKO. Mr. Schleimer? 

Mr. SCHLEIMER. PJM actually looked at fuel diversity in a report 

they released a couple months ago and they found that fuel diversity, I think Mr. Kelliher referred to this already, is actually increasing in PJM, not decreasing. 

Mr. TONKO. Thank you. 

Mr. Reasor? 

Mr. REASOR. Again, that wasn’t their design. 

Ms. LINDE. Yes, I agree. It was not their design. 

Mr. SCHISLER. It was not their primary design, no. 

Mr. TONKO. And Mr. Glenn? 

Mr. GLENN. Yes. 

Mr. TONKO. OK. And obviously state policy decisions can affect 

the fuel supply. Should state policies seek to promote or maintain 

fuel diversity anyone? 

Mr. GLENN. Yes. 

Mr. TONKO. Ms. Linde or Mr. Glenn? 

Mr. GLENN. Yes, just to put it in perspective, one dollar for 

MMBTU increase in the price of natural gas for our customers in 

Florida will increase a fuel bill by $200 million. So if you think 

about that, fuel diversity and overall diversity in your generation 

planning is critically important. 

Mr. TONKO. And Ms. Linde, I believe you wanted to respond? 

Ms. LINDE. Yes. I do believe that states have a role in fuel diversity. Ideally, it should be handled on a regional or a federal basis 

because electricity markets are interconnected, but states have a 

legitimate role and the courts have been supporting that. 

Mr. TONKO. Should the states give preference to reach environmental goals? 

Ms. LINDE. Our view at PSEG is that it depends on the state. 

States, that is a local issue. Some states have renewable portfolio 

standards, others do not, and it is up to the constituents in those 

states to decide what they believe is most important. Ultimately, 

112 

we have to do what is right for the customers and for our nation, 

and a state is going to respect what their customers and their citizens want. 

Mr. TONKO. I believe my time is up, so Mr. Chair, I yield back. 

Mr. OLSON. The gentleman’s time has expired. The chairman 

calls upon the gentleman from the Commonwealth of Virginia, Mr. 

Griffith, for 5 minutes. 

Mr. GRIFFITH. Thank you very much. I appreciate the chairman 

from Texas recognizing Virginia and do appreciate being with you 

all. I apologize that I have been in another committee hearing for 

part of the time, so I apologize in advance if I go over some previous territory. 

I will say based on the opening statements and so forth that I 

recognize that we need fuel diversity, but I also recognize that I 

have some differing opinions with some of the members of the 

panel because while market forces certainly have played a role, the 

regulatory scheme in relationship to whether or not a utility continues to use an existing, or what was then an existing, coal-fired 

power plant has clearly been affected by regulation as well. 

And some of those, because of the cost to their ratepayers, would 

have continued to use some of those coal-fired power plants for 

some time in the future if—and I believe it will be a low-cost natural gas supply for a number of years in the future—as they went 

to replace those facilities they would have replaced them probably 

with some mixture including a higher amount of natural gas, but 

it was artificially moved forward, in my opinion, by regulation. So 

I do disagree there. 

I do think though that we should let the market work it out, trying to keep a diversity including coal because coal still accounts for 

30 percent of our power source and that if we eliminated subsidies 

in the marketplace for all of the different potentials that coal would 

be in a much better position to play a role in that marketplace. 

OK, so I got all that off my chest and I do believe that coal is 

going to need to be important when we look at high usage periods, 

because you may be able to build a lot of pipelines but you can’t 

build enough pipelines to handle all the aspects of a polar vortex. 

And yet you can put coal in the back 40 and have it there ready 

to go in cases of emergency and when things don’t work out quite 

the way, which is why in the eastern part of Virginia they just allowed two coal-fired power plants to fire back up because they 

haven’t gotten the other supply there yet and they have got a 

transmission problem, so we are going to have to go back to coal 

in a place where it had already been eliminated. 

So that being said, let me move on. I am going to call you Senator Reasor because that is how I knew you originally. It is good 

to see you. We talked earlier today. But Mr. Reasor and I, Senator 

Reasor and I served at one point in time in our past in the Virginia 

legislature, he in the Senate and I in the House. It is good to have 

you here today. 

Having missed some of it, I have got a question for you but I am 

also going to give you an opportunity right now, is there anything 

that you haven’t had an opportunity to speak on that you desire 

to speak on here today? 

Mr. REASOR. I think I am good, Congressman. 

113 

Mr. GRIFFITH. All right. 

Mr. REASOR. I appreciate the opportunity. 

Mr. GRIFFITH. All right, so my question deals with procuring capacity is necessary for a healthy wholesale market. As a PJM member, I understand you may be unable to self-supply the capacity 

that is required. Is this true and how would you resolve the situation? And I am really curious how the self-supply issue got turned 

on its head. But you can talk about that some more. 

Mr. REASOR. Thank you, Congressman, for the opportunity and 

you are exactly right. And I would go back to basically just saying 

this. PJM under their original structure did allow utilities like us 

who are load serving entities to have the opportunity to first look 

to our self-supply, and then if there was not enough capacity within PJM they would obtain that capacity and we would pay those 

costs as members of PJM. That worked fine. We liked that situation, we thought it worked well. 

We are not sure—well, we have some ideas as to why the 

changes were made because other parties and participants within 

PJM saw the markets differently and wanted to kind of move the 

system around a little bit and so they convinced PJM that they 

should maybe do away with the idea of looking first to self-supply, 

but look first to the capacity markets that PJM instituted. 

Now I will say that after a period of time we were able to reach 

a compromise and they made some exceptions to that rule that did 

allow us to look first to our self-supply and as long as that was in 

place that worked, but the courts have now said that may not be 

exactly because of a FERC ruling the way it will be allowed, so we 

are a little concerned about the future. 

Mr. GRIFFITH. And would I be correct, and I am going to need 

a yes or no on this one because I am running out of time, but 

would I be correct if that makes it more difficult for you all to look 

for, say, investments in the coal fields where you might put a 

closed-loop hydro project inside of a coal mine that policy makes it 

more difficult for you to even consider that, doesn’t it? 

Mr. REASOR. It makes it more difficult for future planning and 

long-term planning and a facility like that would have to fit that 

category. 

Mr. GRIFFITH. I appreciate it. 

Ms. McAlister, real quick. Public power utilities like the city of 

Salem and the town of Richlands are governed by their city councils. How is the role of these elected officials and local decision 

making respected within the capacity construct, and you have got 

10 seconds. Oh, you can get a little more, got a little more. 

Ms. MCALISTER. Thank you. I don’t think it is in particular, because the construct as we have talked about was designed to do 

least-cost dispatch and it is not conducive with local decision making. 

Mr. GRIFFITH. I appreciate that. 

And thank you for the extra time, Mr. Chairman, I yield back. 

Mr. OLSON. The gentleman’s time has expired. The chair calls 

upon the gentleman from Ohio, Mr. Johnson, for 5 minutes. 

Mr. JOHNSON. Well, thank you, Mr. Chairman. 

And Ms. McAlister, thank you for being here today. As a public 

power producer owning generating units throughout my home state 

114 

of Ohio and a few hydro sources as well along the Ohio River adjacent to my district, I have appreciated your thoughts and insights 

today. 

In your testimony you state that we must not lose sight of improving our current price formation processes regarding transparency of operator decisions, modeling, all known constraints, and 

more accurate price formation rules during periods of transmission 

congestion and volatile fuel prices. Can you elaborate just a little 

bit and explain what modeling all known constraints might entail? 

Ms. MCALISTER. Thank you, Congressman Johnson. What we are 

really getting at there is that there actions that can be taken on 

the energy market and we have focused today on the capacity construct that we think needs a lot of work, but there is also work to 

be done on the energy market side of it. And FERC has been taking proactive actions to improve price formation through a series 

of technical conferences and we are very supportive of those actions 

and think that there is still more to be done as far as modeling and 

ensuring that during times of constraints we are getting the best 

least-cost energy. 

Mr. JOHNSON. OK, all right. You talked about churning of RTO 

rules. How frequent are these rules changed and what is the impact of this churning that you describe? 

Ms. MCALISTER. Well, since 2010, in PJM there have been 27 significant changes that were filed at FERC that fundamentally have 

changed the nature of PJM’s capacity construct. And the effect of 

those is that the construct has become increasingly complex and it 

also doesn’t ensure transparent or stable prices and it makes longterm planning very difficult. 

So we think that it is time to acknowledge the capacity construct 

as designed might not be cutting it and we need to go back and 

do a comprehensive evaluation of whether we need to change. 

Mr. JOHNSON. OK, all right. Thank you, one more. You also mentioned in your testimony that ‘‘new energy products must also 

incentivize the retention of sufficient nonvariable resources to ensure load continues to be served at all times.’’ Can you elaborate 

on this? What would that entail? 

Ms. MCALISTER. Well, what we were talking about there is in 

PJM with the recent capacity performance changes the definition 

of what a capacity resource changed and in order to qualify as a 

capacity resource you have to be available 24/7/365. And what that 

does is it negatively impacts intermittent and renewable resources. 

And so one idea that we have is through bilateral contracting it 

would value those resources on par with some of the other resources that do meet the capacity performance definition. 

Mr. JOHNSON. Let me make sure I understood this. So you would 

say that alternative sources that are not necessarily available 24/ 

7/365 would be evaluated on the same basis as other sources, or is 

it the opposite of that? 

Ms. MCALISTER. No, no. Well, I think what we would do is if you 

allow bilateral contracting to have broader use then those customers that value those attributes pay what they think it is worth. 

And then the other resources, for example, coal, the customers that 

value coal resources would pay through bilateral contracts the 

value of what they see coal being worth. 

115 

Not exactly on par, I mean they have different values. Some 

can’t, if the wind isn’t blowing it doesn’t operate. So I am not saying that they are equivalent as resources, just that they should be 

allowed to be valued by the customers who want those particular 

attributes. 

Mr. JOHNSON. OK, all right. 

Mr. Glenn, you mentioned most permitting regulations do not 

impose a timeframe for agency action. Can you elaborate on the 

reasonable shot clock for decisions that you mentioned in a project 

delay your company is facing? 

Mr. GLENN. Thank you. To give you a little context, we had a 

hydro—— 

Mr. JOHNSON. You have about 25 seconds. 

Mr. GLENN. We had a hydro relicensing matter. It started, we 

filed our application 2 years before the license was to be issued 

pursuant to the law. That was in 2005, I believe. 9 years later we 

receive that permit, so to me that is not a reasonable shot clock. 

It has to be something less than that and obviously it is a balance. 

But we need to have some type of deadlines imposed. 

Mr. JOHNSON. OK. All right, well, thank you. 

Mr. Chairman, I yield back. 

Mr. WALBERG [presiding]. I thank the gentleman and now I am 

pleased to recognize the fully repaired and recuperating gentleman 

from Missouri, a man we respect and glad to have you back with 

us, Mr. Long. 

Mr. LONG. Thank you, Mr. Chairman. 

And Mr. Glenn, you state in your testimony that the original 

principles and the needs-based application of PURPA have been 

overtaken by dramatic advances in the energy marketplace and 

many of the requirements of PURPA are unnecessary. Can you expand on why market changes have made much of PURPA unnecessary? 

Mr. GLENN. Yes. I would use North Carolina as a good example 

of this, so when we look at 7 years ago, North Carolina had—— 

Mr. LONG. You might want to stay on your mic. I know you can’t 

see me through them, but it is fine. You are not missing much. 

Mr. GLENN. So 7 years ago we had 20 megawatts of solar capacity in North Carolina. Today we have 2,000 megawatts and it is 

largely due to PURPA-mandated contracts that we have to take 

and pay for those contracts even though we may not need those resources. We have another 5,000 megawatts in the queue. 

To put that in perspective, that covers roughly three-quarters to 

almost the entire square footage of Washington, D.C. with solar 

panels and that comes at a cost to our customers. And we currently 

believe right now that contracts that we signed not 2 or 3 years ago 

are out of money and will be over the 10 to 15 years by about a 

billion dollars. That is a billion dollars that our customers are 

going to pay more than they otherwise would have. 

Mr. LONG. So that kind of explains my next question, how you 

tell these experience and operational challenges due to PURPA, 

correct? 

Mr. GLENN. The operational challenges are significant and they 

are becoming more and more significant because there are no 

ground rules on where those utilities are placed. It placed it where 

116 

the cheapest land may be and so our system wasn’t designed to 

handle a significant concentration, for example, of PURPA solar 

contracts in one area of our state. That is starting to have operational impacts on the way our system can handle that type of influx that comes online just like that and goes away with cloud 

cover or a thunderstorm just like that. 

Mr. LONG. What are some of the recommendations for updating 

PURPA to reflect the changing marketplace you have? 

Mr. GLENN. I think any updates to PURPA should be guided by, 

really, two principles and that is affordability to customers and reliability to the grid. And I think within that there are ways in 

which I think PURPA could be amended that will get at and really 

be a benefit to all of our customers. 

Mr. LONG. OK. You also highlight the need to address workforce 

readiness giving the changing industry and new investments and 

grid modernization. Can you discuss Duke Energy’s efforts to close 

this workforce skills gap? 

Mr. GLENN. Yes. Right now we have roughly 30 percent of our 

employee base is retirement-eligible and so we are going to need 

to replace that workforce and with the grid modernization investments that we are making that is going to require a whole new 

cadre of employees to come online. 

So what we are doing in our various states in which we operate 

is working with community colleges, working with technical 

schools, and working with universities to turn out more relay technicians, more qualified people who can do this type of work, more 

engineers. 

So this is, for example, in North Carolina alone, this is going to be a jobs driver of our $13 billion investments just in that state 

alone, about 14,000 jobs a year. And those are good wage, good 

quality jobs. And so we are working with the university systems all 

throughout and the high school systems to get a qualified good 

workforce who live and work in those communities. 

Mr. LONG. And so it is kind of a double whammy. You are losing 

30 percent, 30 percent of your people are retirement-eligible and 

you are going to add a whole new section to your company. 

Mr. GLENN. So we have got to replenish the old and we have got 

to infuse it with new employees as well. 

Mr. LONG. And I appreciate your use of community colleges and 

such. I know they are very successful in my area. But what can you 

do to ensure workforce training programs reflect the changing industry needs? 

Mr. GLENN. I think we have got to work hand in hand with our 

school systems, K–12 as well as high school as well as our community colleges in developing curriculums. And that is what we are 

doing, actually, in a lot of these community colleges is we develop 

curriculums. We find professors, so to speak, and we will donate 

money and resources, transformers, for example, that they can 

work on. So it needs to be hand in glove with, it is really a publicprivate partnership. 

Mr. LONG. OK, thank you. 

And I am out of time, Mr. Chairman. I yield back. 

Mr. WALBERG. I thank the gentleman and I recognize myself for 

my 5 minutes of questioning now. 

117 

I certainly appreciate the hearing, the context of the hearing 

today, and I would like to thank the panelists for what you brought 

to the table, literally, for us this morning. Yesterday evening I saw 

a white paper by former FERC Commissioner Tony Clark that 

called for the reform of the outdated Public Utilities Regulatory 

Policies Act of 1978, otherwise known as PURPA, and I appreciate 

the gentleman from Missouri’s questions on PURPA. It is an important issue I think we need to discuss today. I don’t believe this 

committee has taken a comprehensive look at this policy since 

2005, and I am very concerned about the negative impacts this law 

is having on Michigan ratepayers, my own included, and potentially on grid reliability. 

Mr. Glenn, I appreciated your comments on PURPA and have a 

few questions for you as well. You stated in your testimony that 

PURPA’s mandatory purchase obligation is directly increasing electricity prices for customers. Would you please elaborate further on 

this? 

Mr. GLENN. Yes. As I responded to Congressman Long from Missouri, we are seeing in North Carolina alone about a billion dollar 

increase above what our customers otherwise would pay. 

Mr. WALBERG. A billion. 

Mr. GLENN. A billion. And that is just in 2,000 megawatts of contracts that have been signed to date. There is another 5,000 

megawatts of these contracts that are in the queue that have not 

yet been built or signed. So this we see as a growing issue and that 

is just one state in which we operate in. 

Mr. WALBERG. What are some other impacts PURPA mandatory 

purchase obligation is having on utilities’ ability to plan and deliver the lowest cost, reliable energy to America’s electricity customers? 

Mr. GLENN. What we are seeing now is an increase in what we 

believe we will continue to see in the future are some reliability 

issues. For example, next year we project with all of the PURPA 

contracts that are coming online in North Carolina, for example, 

that we are going to have to dump power generated by some of our 

nuclear plants to other consumers of power or we are going to have 

to ramp down a nuclear plant. And a nuclear plant is not made—— 

Mr. WALBERG. To ramp down. 

Mr. GLENN [continuing]. To cycle and to ramp-run. And so those 

are significant reliability issues and a nuclear plant is our lowest 

cost operating plant for our customers. 

Mr. WALBERG. And this is because of outdated PURPA rules and 

standards? 

Mr. GLENN. That is correct. 

Mr. WALBERG. Are traditional baseload resources such as nuclear 

energy that can operate 24/7 as you mentioned being undermined 

in any other ways? This is important to me. We have Fermi in my 

districts. We have Fermi 3 licensing already in place, a lot of uncertainty how we move forward. 

Mr. GLENN. And it places, you know, the dispatch ability of a nuclear plant that is a baseload that runs 24/7. So that has an adverse impact on our long-term ability to plan in how do we use and 

operate and maintain those resources. 

118 

Reliability and affordability and increasingly clean energy will 

always be our mission at our company and we will not compromise 

that at all. But we have to go in with open eyes at PURPA and 

really look at the facts and see what can be changed for the benefit 

of our customers. 

Mr. WALBERG. Along that line then let me ask you, I have heard 

that developers are taking advantage of PURPA to force you utilities to purchase increasing amounts of electricity from them more 

so than originally required by law, more specifically, the one-mile 

rule. Could you explain this and the impacts it is having on the 

utility industry, the one-mile rule? 

Mr. GLENN. The one-mile rule what we are seeing is developers 

in some of their projects are gaming the system where you can 

place your systems just beyond one mile of each other to get under 

the PURPA requirements. So I think it would be well served for 

the committee to just review on a fact basis what does this look 

like and how might it be addressed in the future so that customers 

aren’t paying more than they should otherwise. 

Mr. WALBERG. So the one-mile rule they are splitting up multiple 

parts of their grid responsibilities and capabilities to game the system? 

Mr. GLENN. That is what it appears to be. 

Mr. WALBERG. Appears to be, yes. OK. Well, I appreciate that information. I would also, in lieu of the fact we are waiting for—well, 

I would certainly yield to my friend from my own home district 

where I grew up in for additional questions. 

Mr. RUSH. I want to thank you, Mr. Chairman. 

Mr. Glenn, you said something that really kind of piqued my interest. Not that you said, but it is one thing. You were describing 

your job development approach at Duke Energy. Can you expound 

on that a little bit more and is that an approach that is shared by 

the industry in terms of utility companies, your approach in terms 

of job creation? I thought it was pretty invigorating. 

Mr. GLENN. It is something that we have shared among our utility colleagues, but it is something that we have focused on in the 

last, particularly in the last 10 years as we have seen our workforce and the demographics of our workforce. 

What we are also doing is, because we are in seven states in 

which we are vertically integrated electric utilities, our folks live 

and work and play and coach Little League in those communities 

and we want to represent and we want to be those communities 

and represent who they are and so that dictates how we hire as 

well. 

And so we are very proud of the fact that we are—and our last, 

13 percent of our last new hires have been veterans, for example, 

and 30 percent have been women. In a traditionally male-oriented 

industry, 30 percent of new hires is a phenomenal accomplishment, 

31 percent minorities of all of our new hires through June of this 

year. 

So we are taking a global approach not only K–12 and then in 

our community colleges with certain skill sectors, but we are making a concerted effort to try to broaden our pool of candidates who 

are coming in. And I think it helps that the energy industry right 

now is an incredibly dynamic and exciting place to be. 

119 

You know, maybe not everybody might think that but we hire 

people for careers and not jobs and then so that I think helps as 

well, so we are very proud of that fact. 

Mr. RUSH. I certainly want to commend you and do for this approach and I think that this approach probably should be duplicated across the industry. Thank you. 

Thank you, Mr. Chairman. 

Mr. WALBERG. Reclaiming my time and I thank you. I thank the 

gentleman, and those are good points. These are good jobs we are 

talking about and they are worth affronting and getting people to 

understand that. 

Now I am pleased to recognize the gentleman from Pennsylvania, 

the subcommittee chairman where I spent part of my morning, I 

am glad that you have made it back here. I recognize you, Mr. 

Murphy, for 5 minutes. 

Mr. MURPHY. Thank you. Thank you, Mr. Chairman. I thank the 

panel and indulge me if I ask for some things you already answered. I have spent the last few hours delving into prescription 

drug costs and several organizations so we have to multitask and 

make these quantum leaps in our actions. 

But I do want to ask about some jurisdictional boundaries. I was 

previously a state senator and so I am aware of a lot of things on 

those issues and also the wholesale and retail markets. But let’s 

look at, do you think states and federal regulators are even on the 

same page sometimes, or are there some problems that occur when 

it comes to jurisdictional issues? Can anybody answer that for me, 

anybody have concerns? 

Mr. KELLIHER. I am happy to start. 

Mr. MURPHY. Thank you, Mr. Kelliher. 

Mr. KELLIHER. There is always some level of tension between 

federal and state electricity regulators and part from the structure 

of the industry and what the states and federal governments are 

regulating. It is different than, say, in the natural gas business 

where producers are not really regulated, the local gas utilities are 

regulated only by the states and then the pipelines are regulated 

only by FERC. 

In the electric industry you have a lot of vertical integration and 

parts of a vertical integrated utility’s activities are regulated by the 

state, parts are regulated by FERC, and then the line is not clear. 

It is the point where there have been three Supreme Court decisions in the last 2 years trying to mark the line. 

And this is, the core acts have been enacted in 1935, so since 

1935 there is still not perfect clarity on the jurisdictional lines between the federal and state to the point where the Supreme Court 

had to parse through that three times. 

Mr. MURPHY. Do they share the same goals or are they different 

kind of goals when it even comes to such things as providing assistance to economically struggle generation, generating units? Do they 

have the same goals, federal, state? 

Mr. KELLIHER. They have different legal duties. I mean FERC 

regulates the wholesale power markets and its basic duty is to assure that prices are just and reasonable. Well, what does that 

mean? It means they have to be high enough to support continued 

120 

investment in the generation that is needed to meet customers’ 

needs but not so high that they reflect market power abuse. 

But sometimes it can mean high prices. When natural gas prices 

were high, wholesale power prices were high. Those wholesale 

power prices weren’t bad because they were driven by high natural 

gas prices. So the price can be high and still just and reasonable, 

whereas the state utility it is charged with retail rates and in some 

cases states have maintained vertically integrated utilities. So you 

go through the classic cost of service regulation and what costs are 

prudent and not prudent. 

In other cases, states have broken up their utilities and required 

them to divest so the utility is a pure wires entity and they are 

buying power, typically relying on some kind of RTO market and 

the state role there is different. The vertically integrated state role, 

they are involved in resource adequacy and what is the supply mix 

of each regulated utility. 

A state role in a competitive market is different. It is, is there 

enough megawatts, is there enough capacity to meet their needs? 

So sometimes those duties clash, but I think many times they 

don’t. 

Mr. MURPHY. Does anybody else want to weigh in on that issue? 

Yes, Ms. Linde? 

Ms. LINDE. I agree with the description that Mr. Kelliher provided about the legal structure, but to respond to your question 

about are their goals the same, I think the fundamental goals, from 

my experience, have been the same. The regulators that I deal with 

at the state level, and I have been at PSEG for 27 years so I have 

dealt with a lot of different regulators at the state level and at the 

federal level, their fundamental goal is to make sure that the 

power is there when needed and it is a reasonable price. That is 

a very commonly shared goal among state regulators and federal 

regulators. 

How to address different policy initiatives, sometimes there is a 

difference because there is a difference in timing on when the state 

has a particular initiative. We have seen a lot of states develop renewable portfolio standards to encourage development of renewables, and now we are seeing some states like New York and Illinois and some others take action to preserve baseload generating 

units. 

The dialogue is occurring at the federal level and there is a dialogue about what is causing that premature retirement of baseload. 

PSEG believes that it is driven by a market flaw. And that dialogue needs to continue to occur because right now we have the 

federally regulated market that is not valuing fuel diversity and 

that lack of recognition of fuel diversity is causing a premature retirement of nuclear and some other baseload units and states reacting much more quickly in some cases as a bridge until the federal 

government and the federal regulators can solve that problem. So 

sometimes there are timing differences. 

Mr. MURPHY. I appreciate that. 

Mr. Chairman, I reflect back on some of the fuel crises and energy crises we had in the 1970s and we were going to make all 

these great changes to the markets and we tried them for a while 

and then dropped them suddenly. 

121 

So the issue of diversity is incredibly important because the sun 

sets, the wind dies. We lose coal plants. We can go for a surge for 

a while with natural gas and then we see prices go up in that and 

then companies say, OK, we have to raise the price now, but we 

also need natural gas to export for chemicals and lots of other 

things there. 

So diversity is the way to go then to make the market more competitive, so thank you very much, Mr. Chairman. 

Mr. WALBERG. I thank the gentleman. Seeing there are no further members wishing to ask questions, I would like to thank our 

witnesses again for being here today and going through this process. You are very helpful to us. 

Pursuant to committee rules, I remind members that they have 

10 business days to submit additional questions for the record, and 

I ask that witnesses submit their response within 10 business days 

upon receipt of the questions. 

Without objection, the subcommittee stands adjourned. 

[Whereupon, at 12:37 p.m., the subcommittee was adjourned.] 

[Material submitted for inclusion in the record follows:] 

122 


26883.069

GREG WALDEN, OREGON 

CHAIRMAN 

ONE HUNDRED FIFTEENTH CONGRESS 

FRANK PALLONE, JR., NEW JERSEY 

RANKING MEMBER 

(!ongress of tbc Wnitcb ~tatcs 

1&)om~e of 1\epresentattues 

COMMITTEE ON ENERGY AND COMMERCE 

2125 RAYBURN HousE OFFICE BuiLDING 

WASHINGTON, DC 20515-6115 

The Honorable Joseph T. Kelliher 

Executive Vice President 

Next Era Energy, Inc. 

801 Pennsylvania Avenue, N.W.; Suite 220 

Washington, DC 20004 

Dear Mr. Kelliher: 

(202)220.-2927 

(202)225-3641 

August 4, 2017 

Thank you for appearing before the Subcommittee on Energy on Tuesday, July 18, 2017, to 

testify at the hearing entitled "Powering America: Examining the State of the Electric Industry through 

Market Participant Perspectives." 

Pursuant to the Rules of the Committee on Energy and Commerce, the hearing record remains 

open for ten business days to penn it Members to submit additional questions for the record, which are 

attached. The format of your responses to these questions should be as follows: (I) the name of the 

Member whose question you are addressing, (2) the complete text of the question you are addressing in 

bold, and (3) your answer to that question in plain text. 

To facilitate the printing of the hearing record, please respond to these questions with a 

transmittal letter by the close of business on Friday, August 18, 2017. Your responses should be mailed 

to Elena Brennan, Legislative Clerk, Committee on Energy and Commerce, 2125 Rayburn House Office 

Building, Washington, DC 205!5 and e-mailed in Word format to Elena.Brennan(iilmail.house.gov. 

Thank you again for your time and effort preparing and delivering testimony before the 

Subcommittee. 

Sincerely, 

;7...-~~ Fred Upton 

Chainnan 

Subcommittee on Energy 

...... 

cc: The Honorable Bobby L. Rush, Ranking Member, Subcommittee on Energy 

Attachment 
123 


26883.070

Questions from The Honorable Fred Upton 

1. Over the last decade, emissions from the power sector have been declining. What role has 

organized electricity markets played in declining emissions? 

Organized markets have played an important role in reducing emissions from the power 

sector over the last decade. The primary focus of organized markets is assuring adequate 

electricity supply at the lowest reasonable cost, and the structure of these markets places a 

relentless pressure on cost. That pressure manifests itself through the deployment of 

newer, more efficient generation facilities and the retirement of inefficient generation. 

Since inefficient generation facilities require more fuel and produce more emissions to 

generate the same electrical output as efficient facilities, the retirement of inefficient 

generation for economic reasons has the effect of also lowering emissions. Most of the 

inefficient generation that has retired in the organized markets has been older coal and 

natural gas generation with high emissions levels, and has been replaced by more efficient 

natural gas generation and renewable generation with lower or no emissions. While these 

same economic pressures exist outside of the organized markets, the transparent price 

signals within the organized markets has led competitive generators to retire older, 

inefficient resources more quickly. Although the object of organized markets is not 

lowering emissions, these markets are ultimately responsible for much of the emissions 

reductions that have occurred in their regions over the past ten years. Of course, other 

factors have played an important role in reducing emissions, including the steep decline in 

natural gas prices, lower demand for electricity, environmental requirements, and customer 

preferences for clean energy. 

a. Do you expect emissions from the power sector to continue to decline into the 

future? 

I expect emissions from the power sector will continue to decline as the U.S. 

electricity supply mix evolves to rely more heavily on wind and solar power, modern, 

efficient natural gas generation, and storage technologies. The transformation of 

the generation fleet is occurring primarily for economic reasons, with lower-cost 

natural gas and renewable generation displacing older, less efficient generation with 

higher emissions. This trend is expected to continue for years to come given the 

continuation of low natural prices and the on-going decline in the cost of wind and 

solar generation. 
124 


26883.071

GREG WALDEN. OREGON 

CHAIRMAN 

ONE HUNDRED FIFTEENTH CONGRESS 

FRANK PALLONE, JR., NEW JERSEY 

RANKING MEMBER 

C!Congress of tbe Wniteb $tates 

:r!)ouse of l&epresentatibes 

COMMITTEE ON ENERGY AND COMMERCE 

2125 RAYBURN HousE OFFICE BuiLDING 

WASHINGTON, DC 2051&-6115 Mujority (202)225 .. 2927 

Mmority {202) 225·-3641 

Ms. Lisa McAlister 

Senior Vice President and 

General Counsel for Regulatory Affairs 

American Municipal Power, Inc. 

1111 Schrock Road 

Columbus, OH 43229 

Dear Ms. McAlister: 

August 4, 2017 

Thank you for appearing before the Subcommittee on Energy on Tuesday, July 18, 2017, to 

testify at the hearing entitled "Powering America: Examining the State of the Electric Industry through 

Market Participant Perspectives." 

Pursuant to the Rules of the Committee on Energy and Commerce, the hearing record remains 

open for ten business days to permit Members to submit additional questions for the record, which are 

attached. The format of your responses to these questions should be as follows:(!) the name of the 

Member whose question you are addressing, (2) the complete text of the question you are addressing in 

bold, and (3) your answer to that question in plain text. 

To facilitate the printing of the hearing record, please respond to these questions with a 

transmittal letter by the close of business on Friday, August 18,2017. Your responses should be mailed 

to Elena Brennan, Legislative Clerk, Committee on Energy and Commerce, 2125 Rayburn House Office 

Building, Washington, DC 20515 and e-mailed in Word format to Elena.Brennan!Z1lmail.house.gov. 

Thank you again for your time and effort preparing and delivering testimony before the 

Subcommittee. 

Sincerely, 

~r*t~ Chairman 

Subcommittee on Energy 

cc: The Honorable Bobby L. Rush, Ranking Member, Subcommittee on Energy 

Attachment 
125 


26883.072

Elena Brennan, legislative Clerk 

Committee on Energy and Commerce 

2125 Rayburn House Office Building 

Washington, DC 20515 

Dear Ms. Brennan: 

August 18, 2017 

Enclosed are responses to additional Member questions for the record of the July 18, 2017 hearing 

entitled "Powering America: Examining the State of the Electric Industry through Market Participant 

Perspectives." As requested, an electronic copy of these responses has also been emailed to your 

attention. We appreciate the opportunity to offer these additional responses, and to participate in 

the hearing. 

lisa G. McAlister 

Sr. Vice President and General Counsel for Regulatory Affairs 

4846-9649-8509, v< 1 

OELAWARE D\:1.'\WAH.J: MUN!CJI',\L fJ.EC!'R!C COill'ORAflON INDIANA CANN!XJON KENTUCKY l!J:I\IHJ\M • lll:R£A • I'AJ)UC'.AH • PA!llS • l'RlNCEfON • WJUJAMS'!X)WN 

MARYLAND !It RUN MICHIGAN CUNTO."' ° COLDWATER • H!USDAU: • MARSllALL • UNION CnY • WYANDO!"Ili OHIO AMI ltltST • ARCADIA • ARCANUM • !lEACH crrY o RIANCI !l$1'!0R 

Wl-MR"fON ° WOODSl11:W • WOODV!IJJ'. • YELLOW SPRINGS PENNSYLVANIA lltRUN • ULAK£LY • CATAWISSA o DUNO\NNON o 1'.1\ST CONEMAUGH • ELLWOOD CiT\1•1\P!lRATr.. o GillARD 

GOLDSl!OllO 0 GROVE CrT\' •llATni:LD • !!OOYEILW!LLE • Ktrr.ll'OWN • !ANSDAU> • tEiliCilTON •l£WlSHillll<Y • Mll'FUNBURC o NEWWli.MlNGfON • PEitKAS!E • Qt!lll(I:RTOV.'N •ROYALTON 

SAlNfCI.AtR•SCIHJYJ.KllJ.!!AVEN•SM!Jlli'ORT•SUMM8UI!LL•WAMI'liM•WA1S0NfOWN•Wl'A111ERLY•ZEUENOPI.EVIRGINIAilfDFORD•DANV!IJ£•rRONTROYAL•MAJn1NSVIU£•nTCiliA"<DS 

WEST VIRGINIA NI:W MI\RTINSVI!.LE • PI !IUI'P! 

AMP• Jill Schrock Road, Suite 100 • Columbus, Ohio4321<) •TeL 614.540.1111 • Fax 614.540.108\ •www.amppanners.org I] ft3 
126 


26883.073

U.S. House Subcommittee on Energy 

Hearing on Powering America: Examining the State of the Electric Industry 

Through Market Participant Perspectives 

July 18, 2017 

Responses to the Additional Questions for the Record by 

Lisa G. McAlister 

Senior Vice President and General Counsel of Regulatory Affairs, 

American Municipal Power, Inc. (AMP) 

We reiterate our apprecation to the subcommittee leadership and members for the 

opportunity to testify, and appreciate the opportunity to augment the comments in our 

written and oral testimony by responding to these questions. 

In response to the Honorable Chairman Upton's question: 

1. In your written testimony, you mentioned the lack of consistent transmission 

planning between markets. How can the planning process move towards 

more consistency and better value inter-regional projects? 

The interregional planning process must move towards more consistency and 

must better value inter-regional projects. Moving away from compartmentalized and 

multiple threshold evaluations and requiring the RTOs to coordinate modeling, planning 

and other cross-border functions would get closer to achieving those goals. Lack of 

effective inter-regional transmission planning has put AMP at risk of not being able to 

economically use its share of its coal-fired plant to serve AMP's load. 

AMP is directly involved in the dysfunction between PJM and MISO regarding 

varying and duplicative obligations on generating resources that seek to serve load 

located in an adjacent RTO. Unfortunately, AMP has been drawn into this matter in spite 

of protests and through no fault of its own but, rather with the Federal Energy Regulatory 

Commission's (FERC) acquiescence, the actions of large transmission owners have 

placed AMP in the position of having a significant portion of its owned resources located 
127 


26883.074

in MISO while the great majority of its load is located in PJM. This unenviable situation 

resulted directly from the decisions by American Transmission Systems, Incorporated 

(ATSI) and Duke Energy Ohio/Duke Energy Kentucky (Duke) to withdraw from MISO and 

participate in PJM. A sizable number· cif AMP's members take service from the 

transmission facilities owned by ATSI arid Duke, so prior to those companies' RTO 

"realignment," a considerable portion of AMP's member load was located within MISO. 

That was the situation that existed when AMP negotiated the purchase of its 

approximately 368 MW share of the coal-fired Prairie State Generating Campus (Prairie 

State) located in Illinois, within MISO's footprint. When ATSI and Duke moved into PJM, 

however, the interconnected AMP members were compelled as a practical matter to 

move into PJM, as well. Consequen.tly;AMPfound itself in the situation in which Prairie 

State and other supply resources remained within MIS01 while after the migration most 

of its load was located in PJM. That outcome was one· over which AMP had no 

control- as the Commission has found, "ATSI and Duke, and not their transmission 

customers, decided to withdraw from MiS0"2 - and it is the situation that continues to 

this day:· 

In order for· AMP •to utilize Prairie;state- for its intended purpose - providing -longterm' power supply service tcvAMP's rrie.mbers in an economical and reliable manner -

AMP is required toutilize·a pseudo-tie from MlSO.foPJM. 'A pseudo-tied generation 

1, It is wQ,~h noting .th<;~t A,M P, al~o hils two hyd,ropower plants that '¥re physically l?cated in MISO's ,footprirt 

that were developed prior to the time FirstEnergy and Duke migrated to MISO that remain s'trande'd in MISO 

as AMP is unable to cost effectively obtain transmission from MISO to PJM to serve AMP's load that was 

mov.ed into PJM as a res~lt ·of the transmission owner decisions. And, even if AMP was able to·obtain· the 

firm transmission service, it would still have the risk and uncertainty associated with the pseudo-tie rules as 

discussed further below. 

2 Midwest lndep. Transmission. System Operator, Inc., 153 FERC 1f 61,101 at P 170 (2015); see a/so 

Midwest lndep. Transmission. System Operator, Inc., 138 FERC 1f 61,140 at P 65 (2012). 

2 
128 


26883.075

resource is one physically located in one RTO, but treated electrically as being in another 

balancing authority area. When a generator is pseudo-tied out of MISO, its "telemetered 

reading or value ... is updated in real time and used as a tie line .. flow in the Area Control 

Error equation but ... no physic.al tie or energy metering actually exists." In .other words, 

generating facilities, like Prairie State, that are pseudo-tied out ofMISO to PJM do not 

reside within the MI.SO Balancing Authority Area, do not participCJte in MISO's markets, 

and MISO loses functional control ofthe unit· 

AMP's decision to pseudo-tie Prairie State into PJM was not made to take 

advantage of more advantageous market conditions in'one RTO or the other; ratner, it 

was a step that was necessary to. utilize Prairi@·State to provjc;le long-term power supply 

service to AMP's members that were moved into .. f?JM. To serve.its PJM load, AMP is 

required by PJM's FERC-approved tariff to pseudo·tie. 

AMP's pseudo-tie became effectiv~oo June 1, 2016. Shortly. thereafter, it became 

evidentto-AMP that the RTOs were both charging.·AMP for congestion over the same 

facilities., In otber words, PJM would charge AM8for congestJo~ on:a transmission facility 

and MISO would also charge AMP for congestion on that same transmission facility .. After 

an inability to achieve an informal resolution of. this issoe, '<AMP filed a cqrnpl;:~int 1:1t FERC 

requesting tbat the RTOs stop. duplicative co.ngestion cha(ges:,;:mc;lrefLJIJd AMP Jor: ,th.e 

duplicE!tive charges that had already been collected: The RTOs .11lave acknowledged the 

double-charging issue as well as independently recognizing various problems that were 

not\esolved for generatiorf p~eudq:tied from MISO)o .P~JM prio(', tciiinplemeritation of. the 

pseudo-ties. Specifically,. the RTOs identified. problems associated with grid reliability and 

adequate modeling (such as coordinated congestion management and the potentiai need 

3, 
129 


26883.076

by MISO to commit or de-commit a pseudo-tied resource that it does not control in order 

to maintain its transmission system within thermal and voltage operating limits); market 

inefficiencies in MISO caused by the dispatch of pseudo-tied generation; and pseudo-tied 

units that retire or suspend operations without adequate notice to MISO and both RTOs 

charging congestion and administrative costs. 

While the RTOs have been slowly working this issue through its Joint Operating 

process since the last quarter of last year, they have not come up with a solution, keep 

pushing the date by which they estimate a solution can be achieved, refuse to address 

the issue of refunding pseudo-tied· generators for the duplicative charges already 

collected, and take up valuable stakeholder time developing new pseudo-tie agreements 

that do not address the current problems: AMP has detailed the lack of progress in a 

response to an RTO status update filed at FEF)C that is attached hereto. 

In sum, ·from AMP's. perspective, itappears that the R·TOs have undertaken a longrunning effort to. restrict the use ,of .exter.11al· capacity resources ·located in one RTO· to 

serve load in the other RTQ,I:Jy:burdening the use of the pseudo-tie to the pointthat itis 

rendered uneconomic. df AMP's use of: Prairie State -to serve its PJM load becomes 

burdened tq the point of being'.uneconomic, AMP's members would be deprived of the 

intended benefits of a resource, in which AMp> has invested significantly and in which the 

revenues derived from any alternative use almost certainly would not cover its members' 

PJM capacity costs. This stranding of new generation runs contrary to FERC's own longrunning effort to remove artificial transactional barriers between RTOs (and especially 

between MISO and PJM). Burdening pseudo-tie arrangements with additional and 

overlapping requirements and costs predictably will impede the use of that mechanism, 

4 
130 


26883.077

which, in turn- also predictably- will reduce competition in the capacity and energy 

markets. Competition from external resources, Which is one of the few forces that exert 

downward pressure on prices in PJM's capacity auctions, has and will suffer as a result. 

Consumers will suffer the higher prices that necessarily will follow an impairment of 

competition. 

PJM and MISO have been working on implementation of a Joint and Common 

Market since 2004. The goal of the Joint and Common Market is to achieve all the 

benefits of a combined market across the footprint that includes both PJM and MISO and 

that meets the needs of all customers and stakeholders on a non-discriminatory basis 

using the electric power grid in the two RTO's regions. The RTOs have acknowledged 

that these benefits will be gained by examining. the, different rules by which the two RTOs 

operate as individual entities and evolving to coordinate· market operations and ensure 

there are. no impediments to trade in either; .both, or: between the markets: The RTOs 

stated that.modifications to their respective operations, tools and processes would be 

deVeloped through' an open stakeholder. process ·designed ·to benefit participants 

regardless of which RTO they belong to;.or if they are in both. As demonstrated through 

the pseudo-tie example, more work is required for the inter-regional planning process to: 

be.more consistent and better value interregiehal projects, 

5 
131 


26883.078

In response to the Honorable Chairman Upton's question: 

2. Your testimony mentioned the need for the transmission planning process 

to provide equitable treatment. Could you offer further examples of 

discriminatory treatment that has occurred in transmission planning and 

your thoughts to make the process fairer? 

Today there is a bifurcated process that works for effectively advancing broadlysupported. transmission projects undertaken for system reliability, but provides scant 

review to "supplemental projects" th;3t are rapidly driving up transmission costs. 

AMP agrees that grid reliability is crucial. PJM, through its Regional Transmission 

Expansion Planning process, over a 15-year horizon identifies transmission constraints 

and other reliability concerns and develpps transmission solutions to mitigate those 

identified reliability criteria violations (these are called baseline projects). 

However, there is a second category of:transmission projects called supplemental 

projects that are not required for compliance with NERC, PJM or even the Transmission 

Owners' system reliability, operational p~r,formance or economic criteria, and are not state 

public policy projects. Rather, supple~entai projects are mostly replacing aging 

infrastructure or hardening th~. grid ..for.added <esilience. These supplemental projects 

···' .;. --'\· 

are made based upon the determination of .tran$mission owners, are not approved by 

PJM or states (with the exception of a siting· process in some states) and are drastically 

increasing in the amount spent on supplemental projects. Specifically, out of 

approximately $30 billion in transmission projects in PJM since 2005, almost $19 billion 

has been for supplemental projects that have been proposed absent transparent criteria 

and models that stakeholders can review and comment on prior to the plans being 

finalized, despite the fact that the transmission owners have turned over the planning and 

operation of their facilities to PJM. While supplemental projects are supposed to be 

6 
132 


26883.079

subject to the same open and transparent process as baseline projects, this is not the 

case. 

The best way to balance grid reliability and concerns about discriminatory 

treatment between baseline and supplemental projects, as well as transmission rate 

increases is to ensure that all stakeholders have an opportunity for early and meaningful 

input and participation in the transmission planning process; that transmission owners 

have transparent, and to the extent possible, consistent criteria and models; and ensure 

that Return on Equity (ROE) rates reflect current economic conditions and additional 

incentives are awarded judiciously to reflect aetuallevels of risk. This could be achieved 

by subjecting supplemental projects to the same rigorous process as baseline projects. 

4812·3479-6109,.v. 5 

Respectfully S\,lbmitted, 

~-t--· -~~ 

Senior Vice President & General Counsel for 

Regulatory Affairs · · 

American Municipal Power, Inc. 

1111 Schrock'Roacr: Suite 10'0 

Columbus, OH 43229 

(614) 540-1111 

lmcalister@amppartners.org 

7 
133 


26883.080

GREG WALDEN, OREGON 

CHAIRMAN 

ONE HUNDRED FIFTEENTH CONGRESS 

FRANK PALLONE, JR., NEW JERSEY 

RANKING MEMBER 

<!Congress of tbe Wniteb .i>tates 

jl)omlc of l\cprcscntatibcs 

COMMITTEE ON ENERGY AND COMMERCE 

2125 RAYBURN HousE OFFICE BuiLDING 

WASHINGTON, DC 20515-6115 

Mr. Steven Schleimer 

Senior Vice President 

Calpine Corporation 

717 Texas Street; Suite 1000 

Houston, TX 77002 

Dear Mr. Schleimer: 

{202) 225-l9?7 

{202) 225 3641 

August 4, 2017 

Thank you for appearing before the Subcommittee on Energy on Tuesday, July 18, 2017, to 

testify at the hearing entitled "Powering America: Examining the State of the Electric Industry through 

Market Participant Perspectives." 

Pursuant to the Rules of the Committee on Energy and Commerce, the hearing record remains 

open for ten business days to permit Members to submit additional questions for the record, which are 

attached. The format of your responses to these questions should be as follows: (I) the name of the 

Member whose question you are addressing, (2) the complete text of the question you are addressing in 

bold, and (3) your answer to that question in plain text. 

To facilitate the printing of the hearing record, please respond to these questions with a 

transmittal letter by the close of business on Friday, August 18, 2017. Your responses should be mailed 

to Elena Brennan, Legislative Clerk, Committee on Energy and Commerce, 2125 Rayburn House Office 

Building, Washington, DC 20515 and e-mailed in Word format to Elena.Brennan@mail.house.gov. 

Thank you again for your time and effort preparing and delivering testimony before the 

Subcommittee. 

Sincerely, 

~~w:+4 Chairman 

Subcommittee on Energy 

cc: The Honorable Bobby L. Rush, Ranking Member, Subcommittee on Energy 

Attachment 
134 


26883.081

U.S. House of Representatives Committee on Energy and Commerce 

Subcommittee on Energy 

Hearing on "Powering America: Examining the State of the Electric Industry through Market 

Participant Perspectives" 

Question for the Record for Steven Schleimer , Senior Vice President, Government and Regulatory 

Affairs, Calpine Corporation 

The Honorable Fred Upton 

Q. In contrast to some of your fellow witnesses, you defend your support of the capacity markets 

by citing to the recent investment of tens of billions of dollars in new generation. Can you 

elaborate on why you believe state subsidies and a "hybrid" market would destroy future 

competitive investment? 

A. As I stated in my testimony, the competitive markets have been successful and continue to 

function quite well, attracting needed investments and reducing wholesale electricity prices. 

The trend towards providing out-of-market subsidies to certain resources is moving the markets 

away from a true competitive model to a "hybrid" model with states deciding which generation 

resources will be utilized rather than the market. Further, the subsidized resources then directly 

compete in the market, suppressing prices for other market participants. Investors are not likely 

to fund new, more efficient and economic generation resources if they face unfair competition 

in the markets and in turn, are potentially unable to recover their investment costs due to low 

revenues from depressed market prices. 
135 


26883.082

GREG WALDEN, OREGON 

CHAIRMAN 

FRANK PALLONE, JR,, NEW JERSEY 

RANKING MeMBER 

ONE HUNDRED FIFTEENTH CONGRESS 

C!tongress of tbe Wniteb .i>tates 

j!'ousc of l\cprcscntatii.Jcs 

COMMITTEE ON ENERGY AND COMMERCE 

2125 RAYBURN HousE OFFICE BuiLDING 

WASHINGTON, DC 20515-6115 

Mr. Jackson E. Reasor 

President and CEO 

Old Dominion Electric Cooperative 

4201 Dominion Boulevard 

Glen Allen, VA 23060 

Dear Mr, Reasor: 

Majority (202) 2'5- 2977 

Minority (202) ?25--3641 

August 4, 2017 

Thank you for appearing before the Subcommittee on Energy on Tuesday, July 18, 2017, to 

testify at the hearing entitled "Powering America: Examining the State of the Electric Industry through 

Market Participant Perspectives!' 

Pursuant to the Rules of the Committee on Energy and Commerce, the hearing record remains 

open for ten business days to permit Members to submit additional questions for the record, which are 

attached, The format of your responses to these questions should be as follows: (I) the name of the 

Member whose question you are addressing, (2) the complete text of the question you are addressing in 

bold, and (3) your answer to that question in plain text. 

To facilitate the printing of the hearing record, please respond to these questions with a 

transmittal letter by the close of business on Friday, August 18, 2017. Your responses should be mailed 

to Elena Brennan, Legislative Clerk, Committee on Energy and Commerce, 2125 Rayburn House Office 

Building, Washington, DC 20515 and e-mailed in Word format to Elena.Brennan@mail.house.gov. 

Thank you again for your time and effort preparing and delivering testimony before the 

Subcommittee. 

Sincerely, 

~~~fi!G Chairman 

Subcommittee on Energy 

cc: The Honorable Bobby L. Rush, Ranking Member, Subcommittee on Energy 

Attachment 
136 


26883.083

U.S. House of Representatives 

Committee on Energy and Commerce 

Subcommittee on Energy 

Powering America: A Review of the Operation and Effectiveness of the Nation's Wholesale 

Electricity Markets 

Response to Additional Questions for the Record 

of Jackson E. Reasor 

The Honorable Fred Upton 

1. As a Load Serving Entity (LSE), what obstacles do you face from wholesale power 

markets in planning your own self-supplied capacity procurements? 

Old Dominion Electric Cooperative is a not-for-profit power-supply electric cooperative, 

which provides capacity and energy to its members, eleven electric distribution cooperatives in 

Virginia, Maryland, and Delaware. These eleven distribution cooperatives provide retail electric 

service to their members, end-use consumers. As the question recognizes, Old Dominion is a 

Load Serving Entity (LSE). 

Old Dominion's members are interconnected to the transmission grid operated by the 

PJM Interconnection, a Regional Transmission Organization (RTO) regulated by the Federal 

Energy Regulatory Commission (FERC). Old Dominion welcomed PJM's conversion twenty 

years ago into an RTO with a single control area and a single transmission tariff, and PJM's later 

expansion into Virginia, because this would provide more economical, non-discriminatory 

transmission service to Old Dominion's members and more wholesale power-supply alternatives 

to Old Dominion. 

I believe that public policy should encourage long-term investments in capacity resources 

by LSEs. This is of particular concern for electric cooperative and municipal electric utilities. 

Cooperative utility LSEs like Old Dominion operate under long-standing business models as notfor-profit entities responsible for meeting their rural electric cooperative customers' power 

supply needs in a safe, reliable and economic manner. Electric power generation assets are 

costly and have long operating lives. Consequently, LSEs have long planning horizons. Old 

Dominion invests in or procures capacity resources with a view to meet its long-term service 

obligations to its consumer-owners in a reliable and economic manner. Old Dominion develops a 

diverse portfolio of capacity resources (including generation and other technologies) that it 

determines best meets its members' needs, based on economic and non-economic criteria. 

In my view, Old Dominion's members and the consumers they serve will fare better if 

competitive wholesale power markets allow LSEs to meet their capacity obligations first by 

building generation resources or procuring them through voluntary long-term bilateral contracts, 

and then by turning to RIO-administered capacity markets for residual needs. 

That is how PJM originally operated its centralized capacity procurement mechanism, the 

"Reliability Pricing Model" or "RPM." In 2006, FERC approved RPM as a residual capacity 

procurement mechanism for P JM to ensure resource adequacy at the least cost: "[W]e conclude 

that, after LSEs have had the opportunity to procure capacity on their own, it is reasonable for 
137 


26883.084

P JM to procure capacity in an open auction at a time when further delay in procurement could 

jeopardize reliability. This, however, should be a last resort." 1 In fact, RPM's annual capacity 

auction was called-and still is called-the "Base Residual Auction."2 

But over time, repeated and significant design changes have made RPM more complex 

and costly. In the ten years since RPM was put in place, it has undergone nearly continuous 

revisions. According to PJM, from 2010 to 2016, there were 24 significant filings at FERC to 

revise RPM, and the 2016 Base Residual Auction was the first such auction with no rule changes 

from the prior year. 3 These frequent changes have created obstacles for Old Dominion and other 

LSEs to plan and use their self-supplied resources to meet their capacity obligations. While Old 

Dominion is building its Wildcat Point Natural Gas Plant in Cecil County, Maryland, as a self- . 

supplied generating resource under P JM' s current tariff rules, those tariff rules have needlessly 

complicated Old Dominion's resource planning and added to its regulatory risks. In addition, a 

recent court decision requires FERC to reconsider the very rule that Old Dominion relied on in 

constructing this plant. 

An important obstacle that RPM creates for LSEs planning to use self-supplied capacity 

arises from RPM's "Minimum Offer Price Rule." This rule imposes a floor on the prices that 

most new gas-fired generators can offer in PJM's capacity auctions. FERC approved this rule in 

2006 because of a theoretical risk that net buyers of capacity could exercise monopsony power to 

lower PJM's capacity auction prices below PJM-determined competitive levels.4 

As originally written, this tariff rule guaranteed that an LSEs' self-supplied capacity 

resource would "clear" in RPM's auctions-i.e., would be accepted as a capacity resource by 

PJM regardless of the LSE's offer price-even if the Minimum Offer Price Rule prevented the 

resource's offer price from lowering the auction-clearing price. But in 2011, FERC approved a 

PJM tariff change that eliminated this "guaranteed clearing" language 5 The guaranteed clearing 

of self-supply is critical for LSEs. If self-supplied capacity does not clear RPM's auction, the 

LSE pays for capacity twice-once for the investment in its own capacity, then a second time to 

pay PJM's costs of procuring the same amount of capacity. But if its self-supplied capacity clears 

the auction, the LSE receives auction revenues from PJM for its self-supplied capacity that offset 

the (identical) costs the LSE must pay PJM for that amount of capacity procured in PJM's 

auction. Guaranteed clearing enables an LSE's self-supplied capacity to be a price hedge against 

volatile PJM capacity auction prices and allows LSEs to use their investments as intended. 

After guaranteed clearing was eliminated, in 2012, P JM stakeholders, including public 

power and rural electric cooperatives, agreed to a limited "Self-Supply Exemption" from the 

Minimum Offer Price Rule, which FERC approved along with other changes to RPM in a 2013 

1 P.!M Interconnection. LLC, 115 FERC 1/61,079 at P 71, order on reh ·g. 117 FERC 1]61 ,331 (2006). 

2 http://www.pjm.coml-lmedia/markets-opslrpm/rpm-auction-info/rpm-base-residua1-auction-fags.ashx?la=en 

3 http://www. pj m .com/-lmedia/committees-groups/committees/mrc/20 160825/20 160825-item-07 -pjm-capacitvproblcm-statement.ashx 

4 P.!M Interconnection, L.LC, 117 FERC 'I! 61,331, at P 104 (2006). 

5 P.!M Interconnection, LLC, 135 FERC II 61,022 at PP 183-184, 191-197, reh 'g denied, 137 FERC 1)61,145 

(2011), reh ·g denied. 138 FERC 1)61,194 (2012), pet.for review dismissed as moot in pertinent part sub nom. N.J 

Bd of Pub Utils. v. FERC, 744 F.3d 74 (3d Cir. 2014). 

2 
138 


26883.085

order.6 The Self-Supply Exemption requires that the LSE meet "net-short/net-long" thresholds, 

meaning the exemption is available only to LSEs that have neither too much nor too little supply 

of capacity relative to their customers' load. However, the Self-Supply Exemption does not 

guarantee the clearing of such self-supplied capacity; it merely allows the qualifying self-supply 

to be offered at a price below the otherwise applicable floor on offer prices. 

The Self-Supply Exemption became available in PJM's 2013 capacity auction. Old 

Dominion was able to use this Self-Supply Exemption when it offered its planned Wildcat Point 

Natural Gas Plant in PJM's Base Residual Auction in May 2014 for the delivery year 2017-2018. 

As a direct consequence of the Self-Supply Exemption, the Wildcat Point plant cleared the 

auction reducing Old Dominion's capacity purchases from the PJM market by approximately 

$50 million 

However, on July 7, 2017, the U.S. Court of Appeals for the District of Columbia Circuit 

(D.C. Circuit) vacated several ofFERC's 2013 changes to RPM rules, including the addition of 

the Self-Supply Exemption, and remanded them to FERC for reconsideration.7 The court's ruling 

puts a cloud over RPM results since the 2013 auction, including the 2014 auction in which Old 

Dominion's capacity from the Wildcat Point plant had cleared, thereby avoiding an incremental 

capacity purchase expense of approximately $50 million. The ruling also casts doubt on the 

continued viability of the current Self-Supply Exemption. Old Dominion does not know what 

FERC will do on remand with respect to the Self-Supply Exemption or other remanded 

provisions of RPM. 

At the Subcommittee on Energy's July 26,2017, hearing on "Powering America: A 

Review of the Operation and Effectiveness of the Nation's Wholesale Electricity Markets," the 

prepared written statement ofPJM's witness Craig Glazer, Vice President for Government 

Policy, attempted to assuage concern over self-supply. The statement maintains that "public 

power entities have been availing themselves of their ability to self-supply and have been 

building new generation in PJM as a result" The statement then lists "recent" generation 

additions as apparent examples. 

However, ofthe 21 generation units listed by PJM, Old Dominion's Wildcat Point 

Natural Gas Plant is the only unit that benefited from PJM's current Self-Supply Exemptionand a court has now directed FERC to reconsider that exemption. One unit was built before PJM 

removed the guaranteed-clearing language in 2011. 8 Three other units used a "unit-specific 

exemption" in 2011 and 2012 before PJM added the Self-Supply Exemption in 2013.9 The other 

listed units were not subject to the Minimum Offer Price Rule, either because they were placed 

in service before P JM instituted RPM in 2007 or because they use a technology, such as 

hydropower, that does not subject them to the Minimum Offer Price Rule. 

In particular, the other Old Dominion plants that PJM lists in its written statement were 

not built "as a result" of RPM's self-supply rules. Old Dominion built its Rock Springs Natural 

6 PJM Interconnection. LLC, 143 FERC ~ 61,090 (2013), reh 'g denied, 153 FERC ~ 61,066 (2015), vacated and 

remanded sub nom. NRG Power Mktg. UC v. FERC, No. 15-1452 (D.C. Cir. July 7, 2017). 

7 NRG Power Mktg. LLC, v. FERC, No. 15-1452 (D.C. Cir. July 7, 2017). 

8 Down Natural Gas Power Plant (Vineland fNJ] Municipal Electric Utility). 

9 Beasley Power Station Units I and 2 (Delaware Municipal Electric Cooperative) [referred to as "Smyrna Natural 

Gas 1-2" in PJM's written statement]; Clayville Natural Gas Unit I (Vineland Municipal Electric Utility). 

3 
139 


26883.086

Gas Units I and 2, and its Louisa Natural Gas Units I through 5 in 2003-before PJM instituted 

RPM in 2007. In addition, the Louisa plants are in Virginia and were built before the utilities in 

Virginia were in PJM. Thus, PJM's implicit suggestion that these plants were built "as a result" 

ofPJM's self-supply rules is simply wrong. 

Furthermore, PJM's written statement asserts that the D.C. Circuit "did not overturn the 

specific agreed-to arrangement that P JM and its stakeholders worked out with public power 

utilities." It is not clear what PJM means by this claim. In fact, the court's opinion clearly states: 

We grant the petitions for review and vacate FERC's Orders with respect 

to unit-specific review, the competitive entry exemption, the self-supply 

exemption, and the mitigation period. We remand the matter to FERC. 10 

Given the constant churn of revisions to RPM, LSEs like Old Dominion face continued 

threats to their long-standing business models to adopt long-term procurement plans and 

integrate them with RPM. The current RPM rules, with a Self-Supply Exemption that is now 

uncertain, needlessly interfere with LSE resource planning and decisions and increase costs to 

consumers. As FERC itself has acknowledged, the "purpose and function" of the Minimum 

Offer Price Rule "is not to unreasonably impede the efforts" of utilities like Old Dominion that 

are "choosing to procure or build capacity under long-standing business models." 11 

a. Are there any potential alterations to PJM's Reliability Pricing Model that 

would ensure LSEs are able to self-supply their capacity obligations while 

balancing PJM's need to ensure regional grid reliability? 

To ensure LSEs are able to self-supply their capacity obligations, while still balancing 

PJM's need to ensure regional grid reliability, RPM's Base Residual Auction should be restored 

to its proper and original role as a residual procurement mechanism--one that is subordinate to 

LSEs' long-term investment or procurement of resources to self-supply their share ofPJM's 

capacity obligations. 

As stated above, in my view, Old Dominion's members and the consumers they serve 

would fare better if competitive wholesale power markets were to allow LSEs to meet their 

capacity obligations by first building generation resources or procuring them through voluntary 

long-term bilateral contracts, and then turning to RTO-administered capacity markets for any 

residual capacity needs. Among other things, this approach would enable LSEs to develop the 

diverse portfolio of capacity resources (including generation and other technologies) that they 

believe best meets their needs, based on economic and non-economic criteria. Centralized 

capacity auctions like RPM cannot effectively replace LSE resource planning, which involves 

many considerations beyond the lowest cost for a single year three years in the future. 

This would require, at a minimum, that PJM return to its pre-2011 approach of 

guaranteed clearing of LSE self-supplied capacity in RPM's auctions. In other words, RPM rules 

should guarantee that LSE self-supplied capacity clears the auction and the LSE receives auction 

revenues at the clearing price--even if P JM keeps a Minimum Offer Price Rule that prevents this 

10 Jd, slip opinion at 16 (emphasis added). 

11 PJM Interconnection, LLC., 137 FERC '1!61,145 (2011) at P 208. 

4 
140 


26883.087

self-supplied capacity from setting an auction-clearing price below the price floor. Returning to 

the guaranteed-clearing provisions which were included in RPM's initial rules would be clearly 

superior to retaining the current, limited Self-Supply Exemption. 

2. As both a transmission owner and transmission customer in the PJM market, how 

effective are existing cost allocation methodologies when planning transmission 

infrastructure? 

Transmission planning and cost allocation for transmission facilities are an important 

issue in PJM. Old Dominion believes that several principles should govern transmission planning 

and cost allocation. 

First, transmission planning for high-voltage transmission facilities for all forms of 

affordable generation should focus on the needs of LSEs and should result from an open, 

coordinated and transparent transmission planning process, as required by FERC. 12 Section 

217(b)(4) of the Federal Power Act, which Congress added in 2005, requires that LSEs' needs 

drive the planning process: 

The Commission shall exercise the authority of the Commission under this 

chapter in a manner that facilitates the planning and expansion of transmission 

facilities to meet the reasonable needs of load-serving entities to satisfy the 

service obligations of the load-serving entities, and enables load-serving entities 

to secure firm transmission rights (or equivalent tradable or financial rights) on a 

long-term basis for long-term power supply arrangements made, or planned, to 

meet such needs. 1 3 

Transmission planning should focus on the needs of the system in order to ensure that 

LSEs can serve their load in a reliable, safe and cost-effective manner. Such planning should 

take into account current needs as well as a reasonable forecast (e.g., 20+ years), since 

transmission assets can have useful lives of several decades, if planned correctly. Transmission 

planning should not be dictated by cost allocation. Instead, once the transmission solution is 

identified, then the costs should be allocated in a manner that is at least roughly commensurate 

with the benefits received. 

I note that in PJM, Old Dominion and others have concerns that not all transmission 

planning is conducted in an open, coordinated and transparent manner. In some instances, 

individual Transmission Owners determine the need for transmission facilities based on their 

own unpublished guidelines as opposed to PJM criteria or the reliability criteria of the Electric 

Reliability Organization. These projects, referred to as "Supplemental Projects", are not subject 

to the same level of P JM Board or P JM Staff scrutiny or evaluation as are other projects included 

in PJM's Regional Transmission Expansion Plan. Therefore, customers are subject to paying for 

costly transmission facilities that may or may not be needed at the scope or the time they are 

constructed. 

12 &e Preventing Undue Discrimination and Preference in Transmission Service. Order No. 890, FERC Stats. & 

Regs. ~ 31,241, order on reh 'g, Order No. 890-A, FERC Stats. & Regs. ~ 31,261 (2007), order on reh 'g, Order No. 

890-B, 123 FERC ~ 61,299 (2008), order on reh"g, Order No. 890-C, 126 FERC ~ 61,228, order on c/ar!fication, 

Order No. 890-D, 129 FERC, 61,126 (2009). 

13 16 U.S.C. § 824q(b)(4). 

5 
141 


26883.088

There are other concerns regarding Supplemental Projects. Local planning for 

Supplemental Projects in the various subregions in PJM has sometimes fallen short of the open, 

transparent and coordinated process required by FERC. In addition, P JM has failed to provide 

necessary consistency in planning for Supplemental Projects in the subregions. FERC has 

initiated an outstanding inquiry into PJM's local planning practices, and ODEC has 

recommended specific revisions to improve local transmission planning in PJM. 14 Consistency in 

all transmission planning in the P JM region should help to facilitate needed transmission while at 

the same time protecting customers from costs for which they do not derive sufficient benefit. 

Planning regions should determine the benefits to be considered in allocating costs of 

high-voltage transmission facilities. Absent regional agreement, costs should be allocated among 

those entities that benefit both initially and over time and take transmission service from the 

transmission providers imposing the charge. Benefits should be tangible and non-trivial and 

related to the reliability and economic delivery of power. Benefits should also be at least roughly 

commensurate with allocated costs. 

For the most part, the existing cost allocation methodologies in PJM are effective from 

the perspectives of allocating costs to the beneficiaries and not impeding development of 

necessary transmission facilities. In PJM, the costs of high voltage transmission facilities 

included in PJM's Regional Transmission Expansion Plan, characterized as Required 

Transmission Enhancements, and the lower voltage facilities needed to support them, are 

allocated 50 percent on a region-wide "postage stamp" basis according to load-ratio shares. The 

remaining 50 percent of costs arc allocated based on a solution-based distribution factor 

method. 15 These cost allocations are updated each year by P JM on behalf of the P JM 

Transmission Owners. Lower voltage facilities, which are deemed Required Transmission 

Enhancements, are cost allocated I 00 percent based on the solution-based distribution factor cost 

allocation method. 16 

There are two problems with the PJM transmission cost allocation methodology, from the 

perspective of a transmission customer paying the costs. First, the P JM beneficiary analysis is a 

snapshot in time. Transmission facilities are long-lived assets and their costs arc recovered over 

many years. P JM' s economic cost allocation methodology does not take into account changes 

which may occur over time in factors which might change the beneficiaries of a project, such as 

the physical characteristics of the system or the profile of the loads being served. This can result 

in a cost-beneficiary allocation which becomes unjust and unreasonable over time. 

Second, while the solution-based distribution factor analysis produces just and reasonable 

cost allocation for the vast majority of projects approved through P JM' s regional planning 

process, it is not well suited for allocating costs of transmission system upgrades that are not 

required to address thermal or voltage-based criteria violations. For such projects, PJM should 

consider alternative cost allocation methodologies in order to ensure that those entities that pay 

14 Monongahela Power Company, eta/., 156 FERC 1161,134 (2016), reh'g dismissed, 157 FERC I; 61,178 (2016); 

see also Response of Old Dominion Electric Cooperative to Order to Show Cause, FERC Docket No. EL16-71-000 

(filed Oct. 25, 2016). 

15 PJM Open Access Transmission Tariff, Schedule 12. 

16 /d 

6 
142 


26883.089

for the facilities receive benefits that arc roughly commensurate with the costs paid. In addition, 

these allocations should be updated on a regular basis. 

An example of the transmission system upgrade situation is a project in the P JM region 

referred to as "Artificial Island." The Artificial Island project involves construction of a new 

230-kV transmission line under the Delaware River and certain other facilities in order to address 

a specific system stability issue and related generation operation issues in an area in Southern 

New Jersey where certain nuclear generating units are located. 17 After Old Dominion and others 

complained over the unreasonable cost allocation for the project, the P JM Board of Directors 

decided to re-study the project and analyze project beneficiaries from alternate perspectives to 

find a reasonable cost allocation. 18 The proceeding before FERC has not yet been resolved, but 

PJM has developed alternative analyses based on the stability benefits provided by the 

transmission solution. There should be flexibility in cost allocation so that unique circumstances 

such as the Artificial Island project can be accommodated to ensure that costs are allocated 

roughly commensurate with benefits received. 

17 See Order Denying Complaint and Accepting Cost Allocation Report, 155 FERC 1!61,090 (2016); reh 'g pending. 

18 See PJM's Informational Filing submitted in FERC Docket Nos. ER15-2563-000, eta!., on Aprill2, 2017. 

7 
143 


26883.090

GREG WALDEN, OREGON 

CHAIRMAN 

FRANK PALLONE, JR" NEW JERSEY 

RANKING MEMBER 

Ms. Tamara Linde 

ONE HUNDRED FIFTEENTH CONGRESS 

<!Congress of tbe mtniteb ~tates 

j!)ouse of l\eprcsmtati\Jes 

COMMITTEE ON ENERGY AND COMMERCE 

2125 RAYBURN HousE OrncE BuiLDING 

WASHINGTON, DC 20515-6115 Majonty (202) 225-?927 

Minonty (202)275-·3641 

August 4, 2017 

Executive Vice President and General Counsel 

Public Service Enterprise Group, Inc. 

80 Park Plaza 

Newark, NJ 07102 

Dear Ms. Linde: 

Thank you for appearing before the Subcommittee on Energy on Tuesday, July 18, 2017, to 

testify at the hearing entitled "Powering America: Examining the State of the Electric Industry through 

Market Participant Perspectives." 

Pursuant to the Rules of the Committee on Energy and Commerce, the hearing record remains 

open for ten business days to permit Members to submit additional questions for the record, which are 

attached. The format of your responses to these questions should be as follows: (l) the name of the 

Member whose question you are addressing, (2) the complete text ofthe question you are addressing in 

bold, and (3) your answer to that question in plain text. 

To facilitate the printing of the hearing record, please respond to these questions with a 

transmittal letter by the close of business on Friday, August 18, 2017. Your responses should be mailed 

to Elena Brennan, Legislative Clerk, Committee on Energy and Commerce, 2125 Rayburn House Office 

Building, Washington, DC 20515 and e-mailed in Word format to Elena.Brennanliilmail.house.gov. 

Thank you again for your time and effort preparing and delivering testimony before the 

Subcommittee. 

Sincerely, 

~~~ Fred Upton 

Chairman 

Subcommittee on Energy 

cc: The Honorable Bobby L. Rush, Ranking Member, Subcommittee on Energy 

Attachment 
144 


26883.091

The Honorable Fred Upton 

Q: In your testimony, you call attention to markets that disadvantage certain resources or fuel types. 

As nuclear resources struggle to compete in wholesale markets, do you feel there's room to monetize 

resource attributes, through the price formation process? 

Linde Response: 

Mr. Chairman, yes, there is room to monetize resource attributes in wholesale markets and FERC has 

the capability to do so. As my earlier testimony stated, fuel diversity is an important aspect of a reliable 

electric system yet our wholesale markets were not designed to ensure fuel diversity. Our electricity 

system is now faced with the premature loss of resources such as nuclear power plants that are relied 

on day in and day out to provide reliable, low-cost and air emission free electricity. These resources are 

at risk because our wholesale markets were not designed to value these assets or fuel diversity. The 

solution is a simple one- wholesale markets need to value these resources by monetizing their 

attributes and recognizing the importance of fuel diversity, fuel security and resilience. I outline below 

the procedural steps that FERC can and should take to ensure that our wholesale electricity markets 

properly value these important attributes. I note however that the necessary changes to wholesale 

market designs witt take time that many base load generators do not have. As a result, it is crucial to 

recognize that state solutions may be necessary to bridge the time until wholesale market designs can 

be modified so that valuable attributes of these resources are adequately recognized. 

Actions FERC should take to ensure fuel diversity and resilience: 

First, FERC should issue an "Order to Show Cause" under Federal Power Act section 206. FERC should 

find that the current RT0/150 tariffs may be unjust and unreasonable because they fail to ensure 

diversity, fuel security and resilience. In response, the RT0/150 would either (1) submit to FERC 

proposed changes to their tariffs to address this gap or (2) provide an explanation as to how their 

current tariffs ensure fuel diversity, security and resilience. FERC would then review the submittals and 

determine if they were indeed adequate to ensure fuel diversity, fuel security and resilience. 

Alternatively, FERC has a pending docket (AD17·11) regarding the integration of public policy objectives 

into the wholesale markets in the Northeast. The FERC could utilize this docket to direct the RTOs/ISOs 

in the Northeast to submit reports within 60-days that explain what steps their regions are taking and 

could take to ensure that fuel diversity, security and resiliency are maintained over the tong-term. After 

the RTOs/ISOs submit the reports, FERC could then use the same section 206 procedure to direct the 

RTOs/ISOs to make market design changes. 

Additionally, over the past several years, you and this committee have done much to encourage FERC to 

maintain its focus on ensuring that the true price of electricity is accurately reflected in the market, 

otherwise known as price formation. Now that FERC has a quorum I encourage you to continue pressing 

this issue front and center with the new FERC commissioners and consider using these price formation 

efforts as a vehicle for monetizing important generation attributes. 
145 


26883.092

FERC has been working to implement these reforms to wholesale energy market design for the purpose 

of ensuring that wholesale energy prices more accurately reflect the cost and value of serving 

customers' electricity needs. To date, FERC has directed reforms that seek to improve transparency in 

the manner in which RTOs/ISOs commit generation resources to serve customers, allow generation 

resources to update their offers on an hourly basis so that they reflect updated system conditions, and 

expand the class of resources that are eligible to set energy clearing prices. PSEG has been a strong 

advocate of these price formation reforms. FERC's energy pricing reforms are a work in progress and 

much work still needs to be done. FERC's ongoing efforts in this area are also capable of serving as a 

vehicle to properly monetize resource attributes and support fuel diversity. For example, PJM recently 

developed several white papers including one titled Pricing Reform: Refining Locational Marginal Price 

(LMP) Formation to recognize the contribution of all resources, including large, inflexible units (often 

referred to as "base load" resources) in serving load in a given interval. This paper dated June 15, 2017 

offers a proposal that is intended to recognize the contribution that generation resources provide to the 

system, including baseload resources, by correcting how base load units are able to set energy prices in 

the market. While this proposal is not a complete solution to the challenges facing baseload resources, it 

is a step in the right direction and should be part of a FERC directive to PJM in the form of an Order to 

Show Cause. 

There are also potential legislative solutions to build off of the work from your leadership and of this 

Committee. Congress could take action to amend the Federal Power Act to require fuel diversity, 

security and resiliency. This amendment would provide clarity that these attributes are of value to 

Congress and the policy of the United States. 
146 


26883.093

GREG WALDEN, OREGON 

CHAIRMAN 

ONE HUNDRED FIFTEENTH CONGRESS 

FRANK PALLONE, JR., NEW JERSEY 

RANKING MEMBER 

<!ongress of tbe Wntteb $tates 

~ouse of l\eprescntatil:lcs 

COMMITIEE ON ENERGY AND COMMERCE 

2125 RAYBURN HousE OFFICE BuiLDING 

WASHINGTON, DC 20515-6115 

Mr. Ken Schisler 

(202)225-2927 

(202)225·-3641 

,August 4, 2017 

Vice President of Regulatory and Government Affairs 

EnerNOC 

One Marina Park Drive; Suite 400 

Boston, MA 0221 0 

Dear Mr. Schisler: 

Thank you for appearing before the Subcommittee on Energy on Tuesday, July 18, 2017, to 

testify at the hearing entitled "Powering America: Examining the State of the Electric Industry through 

Market Participant Perspectives." 

Pursuant to the Rules of the Committee on Energy and Commerce, the hearing record remains 

open for ten business days to permit Members to submit additional questions for the record, which are 

attached. The format of your responses to these questions should be as follows: (I) the name of the 

Member whose question you are addressing, (2) the complete text of the question you are addressing in 

bold, and (3) your answer to that question in plain text. 

To facilitate the printing of the hearing record, please respond to these questions with a 

transmittal letter by the close of business on Friday, August 18, 2017. Your responses should be mailed 

to Elena Brennan, Legislative Clerk, Committee on Energy and Commerce, 2125 Rayburn House Office 

Building, Washington, DC 20515 and e-mailed in Word format to Elena.Brennan@mail.house.gov. 

Thank you again for your time and effort preparing and delivering testimony before the 

Subcommittee. 

Sincerely, 

?~4tF Fred Upton 

Chairman 

Subcommittee on Energy 

.. 

cc: The Honorable Bobby L. Rush, Ranking Member, Subcommittee on Energy 

Attachment 
147 


26883.094

Responses of Kenneth D. Schisler to Member Questions from the July 18, 2017, Subcommittee on 

Energy Hearing, "Powering America: Examining the State of the Electric Industry through Market 

Participant Perspectives" 

Responses to the Honorable Fred Upton, Chairman, Subcommittee on Energy 

1. last year, your company and the demand response industry had a very big win before the 

Supreme Court. The landmark ruling in FERC v. EPSA preserved FERC's jurisdction over 

demand response in the wholesale electricity markets and also upheld the principle that 

demand response resources should be compensated at the same price as generatiors. 

a. In the wake of the Court's decision and the regulatory certainty it provided, what's 

been the the effect on the demand response industry? Have you seen additional 

opportunities for demand response participation. 

The Supreme Court decision helped stabilize the industry and ensured that over 10,000 MW of demand 

response participating in FERC jurisdictional wholesale markets would continue to be able to participate. 

This was a big win. However, the win here was primarily a preservation of the status quo ante, rather 

than the creation of significant new opportunities. The Supreme Court reviewed a D.C. Circuit decision 

that eliminated demand response from FERC jurisdiction, which decision greatly destabilized the 

industry and upended a decade of effort building DR capabilities in FERC-jurisdictional wholesale 

market. 

The decision also affirmed a FERC regulation for determining compensation for demand response 

participating in wholesale energy markets, following a period in which several of the FERC-jurisdictional 

wholesale markets had developed several different ways to compensate demand response in energy 

markets. This part of the decision was favorable for the demand response industry, but the impact has 

been limited thus far for a variety of reasons. First, energy prices have been relatively low since the 

Supreme Court decision in much of the United States, making it more attractive for customers to 

consume energy rather than participate in demand response. Second, prior to the decision, demand 

response participation in energy markets had been, in comparison to capacity markets and reliabilitybased demand response products, relatively small. Economic demand response was virtually nonexistent during the litigation because of the potential for refunds if the D.C. Circuit decision had been 

upheld. With the legal uncertainty removed, economic demand response should be a growth 

opportunity. 

The Supreme Court decision has stimulated additional investment in demand response and new 

advanced energy technologies. It is important to understand that principle underlying the decision 

didn't just impact demand response, but other distributed energy resources (DER) such as energy 

storage, vehicle to grid technologies, and others. If customers were prohibited from participating 

directly or through aggregators in FERC jurisdicitonal markets, it would have negatively impacted the 

commercialization of a variety of new energy technologies and innovation in distributed energy 

resources. The recent acquisition of EnerNOC by the Enet Group, one of the largest electricity companies 

in the world, is a clear example of the optimism for the future of DERs, including demand response, in 

the U.S. and around the world. 
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With the Supreme Court decision, technological advances in dynamic management of customer 

demand, and the declining costs of energy storage, there is now the potential to unleash broader 

participation from customers in wholesale markets, including energy and ancillary markets where 

participation has been limited. Still, three critical elements are necessary to achieve this potential: 

1. A Non-discriminatory market design that recognizes the attributes of Distributed Energy 

Resources without creating unnecessary barriers to entry across all FERC-jurisdictional 

markets. 

2. State regulators and utilities in the Midcontinent lndpendent System Operator (MISO) and 

Southwest Power Pool (SPP) markets seeking broader collaboration with third party 

technology and services providers, and leveraging the capabilities and private capital of nonutility agents working with or through utilities to develop demand response potential. 

3. A constructive regulatory and market platform in the California Independent System 

Operator (CAISO) territory. 

On item 2 above, FERC Order 719 allowed state regulatory authorities to prohibit end-use customers 

from participating in wholesale markets either directly or through third-party demand response 

providers. With the exception of Illinois, every state in the MISO footprint chose to enact this 

prohibition. While many utilities offer interruptible tariffs to their customers that can be used to offset 

wholesale capacity requirements, few utilities offer customers' demand response resources into the 

wholesale energy and ancillary markets. Participation in these markets typically requires a higher degree 

of technology and risk tolerance than what is found in utility interruptible programs. Moreover, 

traditional state regulatory structures do not stimulate efficient levels of investment in demand 

response by utilities. 

In order to achieve efficient levels demand response participation in MISO, active collaboration is 

needed between state regulators, utilities, and third party DER/DR aggregators. This can be achieved in 

a manner consistent with the vertically integrated nature of Midwest states. It should be acknowledged 

that recently several Midwest states have demonstrated leadership and are actively considering how to 

stimulate broader distributed energy resource participation, including third parties working through or 

in conjuction with utilities. 

With respect to Item 3 above, while California permits wholesale demand response participation, 

significant demand response investment and potential remains sidelined in CAISO due to significant 

uncertainty with regard to the management by CAISO of demand response participation. Despite its 

large size and good fundamentals for demand response, a number of barriers and unpredictable and 

disordered decision-making is a concern that has resulted in CAISO having a woefully underdeveloped 

market potential for demand response. 

In your testimony, you noted that demand response resources reduced wholesale market costs by 

nearly $10 billion dollars in PJM for the current delivery year. Can you explain how demand response 

accomplished such a significant reduction? 

a. Were these savings realized in the energy markets, capacity markets, or both 

markets? Are these savings net of payments to demand response resources? 
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This figure comes from a report from the PJM Independent Market Monitor, with a citation provided 

below, and is specific to capacity market savings. The quote from Page 6 of the report is: 

"The inclusion of sell offers for Demand Resources and Energy Efficiency resources had a significant 

impact on the auction results. Based on actual auction clearing prices and quantities and make-whole 

MW, total RPM market revenues for the 2017/2018 RPM Base Residual Auction were $7,512,229,630. If 

there were no offers for DR or EE in the 2017/2018 RPM Base Residual Auction and everything else had 

remained the same, total RPM market revenues for the 2017/2018 RPM Base Residual Auction would 

have been $16,859,658,203, an increase of $9,347,428,573, or 124.4 percent, compared to the actual 

results." 1 We are not aware of any publically available figures on energy and ancillary market savings, 

and since the current delivery year is still in progress, it would not be possible to calculate savings over 

the entire time period. 

The driver for the large savings is most likely a result of willingness from demand response resources to 

provide capacity at a more competitive cost than certain generation assets. If demand response had not 

participated in the auction, supply would have been lower, and the clearing price for PJM capacity 

would have been substantially higher. 

1 Monitoring Analytics. Analysis of the 2017/2018 RPM Base Residual Auction. The Independent Market Monitor 

for PJM. October 6, 2014 
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GREG WALDEN, OREGON 

CHAIRMAN 

ONE HUNDRED FIFTEENTH CONGRESS 

FRANK PALLONE, JR., NEW JERSEY 

RANKING MEMBER 

<!Congress of tbt Wntteb ~tates 

J!)ou!:$c of l\eprcsentnttbes 

COMMITTEE ON ENERGY AND COMMERCE 

2125 RAYBURN HousE OFFicE BuiLDING 

WASHINGTON, DC 20515-6115 

Mr. Alex Glenn 

Senior Vice President 

Duke Energy Corporation 

550 South Tryon Street 

Charlotte, NC 28202 

Dear Mr. Glenn: 

Majonty (202) 225-2927 

Minority (202)225-3641 

August 4, 2017 

Thank you for appearing before the Subcommittee on Energy on Tuesday, July 18, 2017, to 

testify at the hearing entitled "Powering America: Examining the State of the Electric Industry through 

Market Participant Perspectives." 

Pursuant to the Rules of the Committee on Energy and Commerce, the hearing record remains 

open for ten business days to permit Members to submit additional questions for the record, which are 

attached. The format of your responses to these questions should be as follows: (I) the name of the 

Member whose question you are addressing, (2) the complete text of the question you are addressing in 

bold, and (3) your answer to that question in plain text. 

To facilitate the printing of the hearing record, please respond to these questions with a 

transmittal letter by the close of business on Friday, August 18, 2017. Your responses should be mailed 

to Elena Brennan, Legislative Clerk, Committee on Energy and Commerce, 2125 Rayburn House Office 

Building, Washington, DC 20515 and e-mailed in Word format to Elena.Brennan@mail.house.gov. 

Thank you again for your time and effort preparing and delivering testimony before the 

Subcommittee. 

Subcommittee on Energy 

cc: The Honorable Bobby L. Rush, Ranking Member, Subcommittee on Energy 

Attachment 
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26883.098

The Honorable Fred Upton 

Chairman, Subcommittee on Energy 

2125 Rayburn House Office Building 

Washington, D.C. 20515 

The Honorable Bobby Rush 

Ranking Member, Subcommittee on Energy 

2125 Rayburn House Office Building 

Washington, D.C. 20515 

August 17, 2017 

Dear Chairman Upton and Ranking Member Rush: 

Thank you for inviting me to appear before the Subcommittee on Energy on Tuesday, July 18, 

2017 to testify at the hearing entitled "Powering America: Examining the State of the Electric 

Industry through Market Participant Perspectives." 

Per your request, I have attached my responses to the questions for the record prior to the 

August 18, 2017 deadline. 

Please let me know if you have any questions or would like additional information. 

Sincerely, 

Alex Glenn 

SVP State & Fed Regulatory Legal Support 

Duke Energy 

1 
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26883.099

The Honorable Fred Upton 

Question: 

1. You testified that it may be time to update PURPA as a result of the changes in the 

market, notably substantial growth in renewable energy due to federal and state 

incentives and policies. Can you describe what circumstances are causing utilities to pay 

above-market costs for electricity under a PURPA contract? 

a. Do you have an example of how much more ratepayers are paying because of 

PURPA contracts? 

b. Do you have specific suggestions on how PURPA should be revised? 

2. You testified that Qualifying Facilities (QFs) under PURPA contract at higher costs due 

to mandatory purchase obligations set out in law. However, the power they sell to the 

wholesale markets play an important role in fuel diversity and resiliency- do those 

added benefits to the grid outweigh slightly higher costs? 

Response: 

a. How could avoided-cost calculations be changed to better integrate QFs into 

wholesale markets at more cost-effective price points? 

1. The circumstances that are causing utilities to pay above-market costs for electricity 

under a PURPA contract are two-fold: 1) the interpretation of "incremental cost" 

(PURPA Section 210) has diverged from both wholesale market price and cost-based 

pricing in a number of jurisdictions and 2) neither the 1978 PURPA statute nor the 2005 

PURPA amendments anticipated that there would be material costs associated with 

integrating large amounts of PURPA power into electric systems and thus, PURPA 

statute is silent on who bears the costs associated with integrating variable, intermittent 

energy deliveries from PURPA facilities into the electric system. As a result, utilities and 

utility customers bear those costs. 

"Incremental Cost" has diverged from actual cost 

Interpretation of PURPA Section 210, at both the FERC and state commission level, has 

led to a situation in which the "incremental cost" or "avoided cost rate" that a utility must 

offer to a PURPA facility for its energy can be markedly higher than the utility's costbased price and/or the wholesale energy price available in a market today. 

While there are a number of examples of how "incremental cost" has diverged from 

actual energy prices across the nation, a well-documented example is in North Carolina, 

where the utility is required to offer to a PURPA facility a price that includes a capacity 

payment, even when the utility has demonstrated that it does not have a new generation 

capacity need. (When a utility does not have a need for new energy generation capacity, 

the value of new capacity is zero.) 

As a result of this divergence from actual energy prices, in North Carolina, the utility 

must offer a rate of approximately $50 per megawatt-hour to a PURPA facility when, in 

actuality, the value should be approximately $35 per megawatt-hour (a price that reflects 

a $35 value of energy and a $0 value of capacity). The effect of this $15 difference 

2 
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becomes very material when amplified by the hundreds of thousands of megawatt-hours 

per year that some utilities must buy from PURPA facilities. 

To better align "incremental cost" with market prices, we recommend a simple remedy: 

Congress should specify, in a PURPA modernization amendment, "no such rule 

prescribed under PURPA Section 210 (a) shall provide for a rate which exceeds the 

lower of actual cost-based or wholesale market prices available to the electric utility (as 

indicated by market clearing prices, prices set through an RFP process, short contract 

prices, published indices, or other such indicia)." 

PURPA fails to address integration cost 

The second reason why some utilities have been forced to pay above-market costs for 

electricity under a PURPA contract is because there is no requirement that the PURPA 

facility (i.e., the solar or wind generator) bear any of the cost for integrating its variable, 

intermittent energy deliveries into the electric system operator. 

As more and more PURPA solar and wind facilities deliver energy, the cost of integration 

has become a material burden to utility customers in a number of regions of the country. 

At significant levels of wind and/or solar penetration, an electric system operator will 

dispatch its generation and operate its transmission facilities differently- often in a more 

costly manner- to accommodate the weather-dependent deliveries of wind solar 

facilities. 

The National Renewable Energy Laboratory estimates that solar and wind integration 

cost range from $1.00 per megawatt-hour to $7.00 per megawatt-hour, depending on 

amount of PURPA capacity, the type of renewable energy, and the size and capabilities 

of the electric system operator who must take the PURPA power. Amplified across 

hundreds of thousands of megawatt-hours from PURPA solar facilities and millions of 

megawatt-hours from PURPA wind facilities, the aggregate cost of integration becomes 

material. 

An example of a situation where the utility and the utility customers are bearing the cost 

of integrating large volumes of solar energy is in Eastern North Carolina, where Duke 

Energy expects that the amount of PURPA solar capacity delivering energy at certain 

hours of the day during the spring and the fall, will be so high that we, Duke Energy, will 

be in a situation where we actually have to "dump" some amount of baseload nuclear 

power. That means that Duke Energy must find a neighbor utility that can accommodate 

that excess power and, most likely, pay him to take the excess power that Duke Energy 

must get rid of in order to maintain line voltages within NERC standards. 

You may ask, so why not just turn off the nuclear power when the PURPA solar is 

delivering at such high volumes? The option of "turning off' baseload coal or nuclear is 

actually very costly and even dangerous, as these plants are not designed to be turned 

off/on daily. In addition, turning off a unit is unadvisable due to the fact that solar output 

varies with weather conditions. For example, if a large front of thunderstorms travels 

through eastern North Carolina, we can expect almost 2,000 megawatts of PURPA solar 

capacity (enough solar to cover 10,000 acres or 15 square miles) to cease production 

within seconds as the storm clouds gather and obstruct the sun. In such a 

situation, "turning off' baseload is not advisable because baseload energy and capacity 

may be necessary to serve customers when PURPA power ceases. 

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26883.101

As a result of the nature of the PURPA must-take power, the amount of PURPA power, 

and the characteristics of the incumbent electric system operator, the utility consumer 

will likely pay two or even three times for energy: once for the nuclear power (which 

cannot be ramped on and off), again for the mandatory purchase of solar power, and 

once again for the cost of paying a neighboring utility to take excess power so that the 

system can safely and reliably accommodate the solar power. 

To remedy this situation, Congress should amend PURPA Section 210 (b) to include the 

following phrase: "The rules prescribed ... shall insure that, in requiring any electric utility 

to offer to purchase electric energy from any qualifying cogeneration facility or qualifying 

small power production facility, the rates for such purchase ... (3) shall obligate the QF 

to operationally integrate its facility with the electric system operator." 

a. The mandatory purchase obligation, whereby a utility must buy power from PURPA 

facilities at specific purchase prices, for a specific term, has a measurable impact on 

the prices our consumers pay for electricity. Key to understanding the impact of 

PURPA is to recognize that when an electric utility purchases power from a PURPA 

facility like a solar generator or a wind generator, those costs are actually borne by 

the utility's consumer, in the same manner in which the cost of natural gas fuel is 

passed on to the customer, without mark-up. 

As for overpayment, Duke Energy calculated the degree to which its North Carolina 

customers were overpaying for PURPA purchase at the end of 2016. At that time, 

Duke Energy had an estimated 1 ,600 megawatts of solar interconnected to and 

selling back to Duke Energy. We estimated that the aggregate cost of the rates for 

purchase offered to PURPA facilities, extrapolated over the expected output of the 

facilities and across the term of the purchase agreement (12-14 years) was $2.9 

billion. If the Duke Energy had not been required to offer payment for capacity when 

the utility's capacity need was zero, or if the utility had not been required to offer 

long-term, fixed price rates to PURPA facilities, and if these contracts were valued at 

the utility's wholesale price today, these contracts, in aggregate would have cost the 

utility customer base just $1.9 billion. Thus, delta between the actual wholesale price 

and the PURPA price, over the course of the PURPA long-term contracts, in 

aggregate, comes to more than $1 billion. 

For reference, sixty percent of all PURPA solar projects nationwide are in North 

Carolina. In 2010, North Carolina had just 20 megawatts of solar installed; enough 

solar to cover about one hundred acres. Today, in North Carolina, there are more 

than 2,000 megawatts of solar power in operation; the equivalent of 10,000 acres or 

15 square miles of solar panels. Bloomberg News actually called the North Carolina 

a PURPA "gold rush" given the number of investors flocking to fund solar farms in 

North Carolina. In addition, there remain more than 5000 megawatts of PURPA 

facility solar awaiting interconnection; that is the equivalent of an additional five 

nuclear reactors' worth of solar capacity awaiting interconnection. 

b. Please refer to my response to Question 1. 

2. No, the added benefits of fuel diversity and "resiliency" do not justify the slightly higher 

prices we are obligated to offer PURPA facilities. Electric utilities constantly assess and 

compare the cost-effectiveness of generation resources like solar, wind, natural gas, 

nuclear, and coal. These calculations take into account costs and benefits of 

4 
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environmental attributes as well as the long-term price of various fuels. As a result of 

these calculations and a tremendous amount of due diligence, Duke Energy now owns 

and operates a fleet of nearly 250 megawatts of solar power within our regulated utility 

companies. This is the amount of solar that state regulatory bodies have deemed 

"prudent" thus far. 

The utility's ability to pay for higher cost resources is extremely limited. Utilities must 

prove that those resources are absolutely essential in order to meet reliability 

requirements, environmental requirements, and/or customer demand. While solar PV 

and wind are non-emitting resources with zero fuel cost, they remain weather dependent 

and are not reliable, dispatchable peaking resources that can be built to meet summer 

afternoon peaks or winter morning peaks. 

As for resiliency, in order for a solar facility to supply electricity during a grid outage to a 

critical facility like a Red Cross evacuation site or fire station, the solar PV system would 

have to be designed with resiliency in mind from the beginning. That is, the solar would 

be combined with other technologies, such as energy storage, switches that safely 

isolate the circuit between the solar facility and the fire station from the rest of the grid 

during an outage, and additional equipment to control the flow and quality of the 

electricity. Today, this additional energy storage, control, and switching equipment is 

very expensive. 

The vast majority of solar PV systems as installed today in the United States are 

technically incapable of providing consumer power during a grid outage; when the grid is 

in an outage, the solar PV systems are required to automatically shut off in accordance 

with IEEE 1547* protocols intended to protect the safety of utility line workers. (If solar 

power were to deliver energy back to the grid during an outage, that would endanger the 

lives of utility line workers.) 

*The Energy Policy Act of 2005 established IEEE 1547 as the national standard for the 

interconnection of distributed generation resources [solar] in the United States of 

America. 

a. There is a simple way to better integrate QFs into wholesale markets at more costeffective price points: Congress should specify, in a PURPA modernization 

amendment, "no such rule prescribed under PURPA Section 210 (a) shall provide for 

a rate which exceeds the lower of actual cost-based or wholesale market prices 

available to the electric utility (as indicated by market clearing prices, prices set 

through an RFP process, short contract prices, published indices, or other such 

indicia)." Such an amendment will prompt FERC rule-making that will enable 

integration of QFs into wholesale markets at more cost-effective price points. 

The Honorable Richard Hudson 

Question: 

1. In your testimony, you discuss how the timely siting and permitting of vital infrastructure 

projects is critical to strengthen the power grid. You also mention how the lack of quorum 

at FERC is preventing action on these crucial infrastructure projects, including natural 

gas pipelines. One such project, the Atlantic Coast Pipeline, will provide clean-burning 

natural gas supplies to growing markets in Virginia and North Carolina. Pipeline 

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construction alone will create 17,000 new jobs and $2.7 billion in economic activity 

across the region, and once operating, the pipeline will save consumers an estimated 

$377 million a year on their energy costs. Additionally, the pipeline will generate $28 

million in annual property tax revenue for local governments along the route. This 

pipeline is one that needs a FERC Commission issued Certificate Order by the end of 

September in order for the company to begin physical work on clearing the right of way 

for the pipeline in October. If these timelines aren't met it could significantly delay the inservice date of ACP. If that happens, what will that do to Virginia and North Carolina 

customers? 

2. You flagged that the preservation of interest deductibility in tax reform is critical for 

electric utilities. Can you expand on what type of capital investments Duke Energy and 

other electric utilities make in the communities they serve and why that is tied to interest 

deductibility? 

Response: 

1. The Atlantic Coast Pipeline needs a FERC Commission issued Certificate Order by the 

end of September in order for the company to begin physical work on clearing the right 

of way for the pipeline in October. If these timelines are not met it could significantly 

delay the in service date of pipeline, potentially resulting in hundreds of millions of 

dollars in delay-related costs to Duke and constrained natural gas supply for our 

customers which could result in higher prices and inability to meet demand. 

2. The electric power industry is the nation's most capital-intensive industry and invests 

more than $100 billion annually to build a smarter energy infrastructure and to transition 

to even cleaner generation sources. Electric companies are significant engines of growth 

across the U.S. economy. 

Just this year, Duke Energy announced a $13 billion, 10-year project to modernize the 

state's electric system. These upgrades will harden the system against storms and 

outages; make it safer and more resilient against cyber-attacks and physical threats; 

help expand renewable energy; generate jobs and stimulate economic growth. It will also 

give 7 million people in North Carolina more information to manage their energy use. 

Duke Energy's 10-year modernization plan for NC will result in: 

Additional bill-lowering tools designed to help customers reduce their energy 

costs 

An average of 13,900 jobs each year 

$10.4 billion in salaries and wages 

• Almost $800 million in state taxes and $550 million in local taxes 

A total economic output of $21.5 billion over the 10 years 

Capital investments such as this modernization plan rely heavily on the ability to deduct 

interest This is due to the highly regulated nature of our businesses as independent 

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state public utility commissions allow electric companies to recover their costs through 

the rates they charge their customers for electricity service. If electric companies are 

unable to deduct interest costs for infrastructure projects, they would pass the higher 

cost of capital on to their customers. Raising electricity prices has a disproportionate 

impact on lower-income customers and small businesses, and hurts the global 

competitiveness of energy-intensive industries in this country. 

Eliminating the ability to deduct interest expense would have a dramatic impact on 

customers' electricity bills. Raising capital through equity is currently more expensive 

than raising capital through debt, and removing the deduction for interest expense will 

not change this fact. Allowing electric companies to continue deducting interest expense 

provides a "win-win" for the American economy. 

7