U.S. GOVERNMENT PUBLISHING OFFICE

30–978 WASHINGTON : 2018

EXAMINING THE STATE OF ELECTRIC 

TRANSMISSION INFRASTRUCTURE: INVESTMENT, 

PLANNING, CONSTRUCTION, AND ALTERNATIVES 

HEARING 

BEFORE THE

SUBCOMMITTEE ON ENERGY 

OF THE

COMMITTEE ON ENERGY AND 

COMMERCE 

HOUSE OF REPRESENTATIVES 

ONE HUNDRED FIFTEENTH CONGRESS 

SECOND SESSION 

MAY 10, 2018 

Serial No. 115–127 

( 

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 

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 

JEFF DUNCAN, South Carolina 

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 

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 

JEFF DUNCAN, South Carolina 

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

New Jersey, opening statement .......................................................................... 5 

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

prepared statement .............................................................................................. 112 

WITNESSES

Tony Clark, Senior Advisor, Wilkinson Barker Knauer, LLP ............................. 7 

Prepared statement .......................................................................................... 10 

Answers to submitted questions ...................................................................... 118 

Edward Krapels, CEO, Anbaric Development Partners ....................................... 32 

Prepared statement .......................................................................................... 34 

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

Jennifer Curran, Vice President, System Planning, Midcontinent ISO .............. 45 

Prepared statement .......................................................................................... 47 

Answers to submitted questions ...................................................................... 130 

Ralph Izzo, CEO, Public Service Enterprise Group, Inc. ..................................... 60 

Prepared statement .......................................................................................... 62 

Answers to submitted questions ...................................................................... 137 

John Twitty, Executive Director, Transmission Access Policy Study Group ...... 70 

Prepared statement .......................................................................................... 72 

Answers to submitted questions ...................................................................... 142 

Rob Gramlich, President, Grid Strategies, LLC ................................................... 86 

Prepared statement .......................................................................................... 88 

Answers to submitted questions ...................................................................... 152 

SUBMITTED MATERIAL

Statement of GridLiance ......................................................................................... 114 

Statement of WIRES ............................................................................................... 116 

(1) 

EXAMINING THE STATE OF ELECTRIC TRANSMISSION INFRASTRUCTURE: INVESTMENT, 

PLANNING, CONSTRUCTION, AND ALTERNATIVES 

THURSDAY, MAY 10, 2018 

HOUSE OF REPRESENTATIVES, 

SUBCOMMITTEE ON ENERGY, 

COMMITTEE ON ENERGY AND COMMERCE, 

Washington, DC. 

The subcommittee met, pursuant to call, at 9:46 a.m., in room 

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

of the subcommittee) presiding. 

Present: Representatives Upton, Olson, Latta, Griffith, Johnson, 

Long, Bucshon, Flores, Hudson, Cramer, Walberg, Duncan, Rush, 

McNerney, Peters, Green, Castor, Welch, Schrader, Kennedy, and 

Pallone (ex officio). 

Staff Present: Samantha Bopp, Staff Assistant; Daniel Butler, 

Staff Assistant; Kelly Collins, Legislative Clerk, Energy/Environment; Wyatt Ellertson, Professional Staff, Energy/Environment; 

Margaret Tucker Fogarty, Staff Assistant; Elena Hernandez, Press 

Secretary; Drew McDowell, Executive Assistant; Brandon Mooney, 

Deputy Chief Counsel, Energy; Mark Ratner, Policy Coordinator; 

Annelise Rickert, Counsel, Energy; Jason Stanek, Senior Counsel, 

Energy; Austin Stonebraker, Press Assistant; Jeff Carroll, Minority 

Staff Director; Jean Fruci, Minority Energy and Environment Policy Advisor; Jourdan Lewis, Minority Staff Assistant; John Marshall, Minority Policy Coordinator; Tim Robinson, Minority Chief 

Counsel; C.J. Young, Minority Press Secretary. 

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

Mr. UPTON. We are going to get started on time. I just want to 

let folks know that our committee has a pretty major bill on the 

House floor this morning, a bill that passed out of committee 49 to 

4, on nuclear waste. 

I know that debate there has started. A number of us have been 

there already to speak. And our colleague, John Shimkus, is helping to manage that bill. So I am not sure that he will be back. But 

we are expecting votes about 10:45, so I am going to try to be quick 

with the gavel. And we will continue after that, but it will be a series of votes. 

Good morning. Today we are continuing our Powering America 

series by taking a closer look at a very important but often underVerDate Nov 24 2008 13:48 Aug 08, 2018 Jkt 037690 PO 00000 Frm 00007 Fmt 6633 Sfmt 6633 I:\MY DOCS\HEARINGS 115\HEARINGS\115-127 CHRIS
2 

appreciated component of our power sector: the electric transmission system. Ever since visionaries such as Edison, Tesla, and 

Westinghouse argued the merits of using direct current versus alternating current, the manner and means by which electricity is 

delivered has been a complicated and, yes, controversial topic. 

We depend on our high voltage network of wires and cables to 

transmit electricity long distances to power everything from our 

iPhones to our economy. A stable and uninterrupted supply of electricity is critical to ensure the public’s health and safety, as well 

as the quality of life that we have come to expect. However, in 

many parts of our country our transmission infrastructure, like our 

Nation’s roads and bridges—particularly if you are in Michigan— 

is aging, congested, and in need of repair or replacement. 

Joining us today is a distinguished panel of experts to help us 

better understand the challenges that the electric transmission sector is facing, as well as the opportunities that may be within reach. 

While much of this debate in the industry is currently focused on 

generator resilience and fuel security, we cannot ignore the vital 

role that the Nation’s electric transmission infrastructure plays in 

connecting the electricity producer to the end-use consumer. And as 

such, I would argue that a resilient and reliable transmission grid 

is no less important. 

Transmission infrastructure, however, does not come cheap, and 

the planning and construction of new lines often takes years due 

to permitting and environmental reviews. Over the past couple of 

years, public utilities and independent transmission developers 

have committed over $20 billion annually to upgrade or replace our 

existing transmission infrastructure. And while that is good news, 

creating jobs, et cetera, sustained investment at similar levels will 

be critical to ensure that Americans have a modern electricity grid 

that can deliver reliable power at a reasonable cost. 

In addition, a predictable regulatory environment and consistent 

policies regarding how transmission projects are approved and paid 

for is essential to reduce financial risk and attract new capital. 

After we passed the Energy Policy Act of 2005, FERC was directed 

to encourage investment in transmission infrastructure projects 

that reduce the cost of delivered power by reducing congestion on 

the grid. FERC responded by granting financial incentives to transmission proposals that met certain criteria. And in subsequent 

years FERC began to issue a series of landmark rules to oversee 

and regulate the details of how transmission projects are planned, 

paid for, and ultimately developed. 

Order 1000 is the agency’s most recent attempt to regulate regional and interregional transmission planning, while also encouraging competition between transmission developers. However, as 

we heard from witnesses in our earlier Powering America hearings, 

while some regional transmission planning processes have become 

more effective, Order 1000 has all but failed to develop new lines 

between and among RTOs and other planning regions. Moreover, 

FERC’s rule allowing merchant developers to now compete against 

traditional utilities to build transmission projects has been criticized as ineffective for a number of reasons. With the help of our 

witnesses, we will explore these and other challenges associated 

with transmission planning, cost allocation, and competition. 

3 

Finally, I hope that we can discuss how alternatives to transmission lines factor into the conversation. While high-voltage wires 

form the backbone of our smart-grid technologies, demand response, energy storage, distributed generation, and microgrids can 

also provide benefits similar to traditional transmission. Since 

these alternatives may improve reliability while reducing environmental impacts and cost to consumers, we should explore whether 

any legal or regulatory barriers stand in the way to prevent energy 

innovation from reaching its full potential. 

So we look forward to hearing from our witnesses. 

I yield the balance of my time to my good friend and colleague 

on the subcommittee, Mr. Long from Missouri. 

[The prepared statement of Mr. Upton follows:] 

PREPARED STATEMENT OF HON. FRED UPTON

Good morning. Today, we are continuing our Powering America series by taking 

a closer look at a very important, but often under-appreciated component of our 

power sector: the electric transmission system. Ever since visionaries such as Edison, Tesla, and Westinghouse argued the merits of using direct current versus alternating current, the manner and means by which electricity is delivered has been 

a complicated and controversial topic. 

We depend on our high voltage network of wires and cables to transmit electricity 

long distances to power everything from our iPhones to our economy. A stable and 

uninterrupted supply of electricity is critical to ensure the public’s health and safety, as well as a quality-of-life that we have come to expect. However, in some parts 

of the country, our transmission infrastructure, like our nation’s roads and bridges, 

is aging, congested, and in need of repair or replacement. Joining us today is a distinguished panel of experts to help us better understand the challenges that the 

electric transmission sector is facing, as well as the opportunities that may be within reach. 

While much of the debate in the industry is currently focused on generator resilience and fuel security, we cannot ignore the vital role that the nation’s electric 

transmission infrastructure plays in connecting the electricity producer to the enduse consumer. As such, I would argue that a resilient and reliable transmission grid 

is no less important. 

Transmission infrastructure, however, does not come cheap, and the planning and 

construction of new lines often takes years due to permitting and environmental reviews. Over the past few years, public utilities and independent transmission developers have committed over $20 billion annually to upgrade or replace our existing 

transmission infrastructure. While this is good news, sustained investment at similar levels will be critical to ensure that Americans have a modern electricity grid 

that can deliver reliable power at a reasonable cost. 

In addition, a predictable regulatory environment and consistent policies regarding how transmission projects are approved and paid for is essential to reduce financial risk and attract new capital. After we passed the Energy Policy Act of 2005, 

FERC was directed to encourage investment in transmission infrastructure projects 

that reduce the cost of delivered power by reducing congestion on the grid. FERC 

responded by granting financial incentives to transmission proposals that met certain criteria. In subsequent years, FERC began to issue a series of landmark rules 

to oversee and regulate the details of how transmission projects are planned, paid 

for, and ultimately developed. 

Order 1000 is the agency’s most recent attempt to regulate regional and interregional transmission planning while also encouraging competition between transmission developers. However, as we heard from witnesses in our earlier Powering 

America hearings, while some regional transmission planning processes have become more effective, Order 1000 has all but failed to develop new lines between and 

among RTOs and other planning regions. Moreover, FERC’s rule allowing merchant 

developers to now compete against traditional utilities to build transmission projects 

has been criticized as ineffective for several reasons. With the help of our witnesses, 

we’ll explore these and other challenges associated with transmission planning, cost 

allocation, and competition. 

Finally, I hope that we can discuss how alternatives to transmission lines factor 

into the conversation. While high-voltage wires form the backbone of our grid— 

4 

smart technologies; demand response; energy storage; distributed generation and 

microgrids can provide benefits similar to traditional transmission. Since these alternatives may improve reliability while reducing environmental impacts and costs 

to consumers, we should explore whether any legal or regulatory barriers stand in 

the way to prevent energy innovation from reaching its full potential. 

There’s no question that as the nation’s electric industry changes, the demands 

placed upon our existing transmission infrastructure will only increase with time. 

Today, our focus will be on how the industry and government can plan for the future to ensure that our power grid is ready to meet the needs of the 21st century. 

Thank you to the witnesses for agreeing to be with us today and I look forward 

toyour testimony. 

Mr. LONG. Thank you, Mr. Chairman. 

I just want to take a few seconds here to personally introduce 

one of the witnesses that is here today with us, a fellow that I have 

known since grade school, and fraternity brothers in college, and 

on through life. And that would be one Mr. John Twitty. 

John is the former CEO of City Utilities in Springfield, in my 

home district, and he now serves as executive director of the Transmission Access Policy Study Group, TAPS. 

Welcome, John. And I want to thank you for lending your expertise to this hearing. Welcome to D.C. 

Mr. UPTON. The gentleman yields back. 

I recognize for an opening statement my friend and colleague, 

the ranking member of the subcommittee, Mr. Rush from Chicago, 

Illinois. 

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. 

And I want to welcome the witnesses to the hearing today. 

Today we will be examining the state of electric transmission infrastructure. 

As you know, Mr. Chairman, there have been many developments in the Nation’s energy portfolio since FERC issued Order 

No. 890 back in 2007 as a way to promote open-access transmission 

services. This rule outlined a planning process for transmission 

providers consisting of nine planning principles, including coordination, openness, transparency, information exchange, comparability, 

dispute resolution, regional coordination, economic planning studies, and cost allocation. 

In 2011, Mr. Chairman, FERC issued Order No. 1000 as a way 

to further improve the planning process within and among geographic regions and also to determine how transmission costs were 

distributed to customers. Order 1000 was also issued to provide additional opportunity for non-incumbent transmission developers to 

compete to build projects within the service territory of incumbent 

utilities. 

Mr. Chairman, in reviewing this policy it appears that the results have been mixed in regards to how successful it has been in 

achieving its goals. We are in the midst of a rapidly changing energy landscape, reflected in part by the emergence of renewable energy sources, low-cost natural gas, State-led Renewable Portfolio 

Standard goals, as well as an increase in energy-efficiency initiatives and overall reductions in energy demand. 

5 

Mr. Chairman, shifting consumer behavior is driving many of 

these changes as customers demand cleaner forms of energy along 

with new tools to more responsibly use the energy they consume, 

both as a way to save money and as a way to save the environment. 

Traditional methods of buying and selling energy are being disrupted by demand response programs where emerging technologies, 

such as energy storage and distributed-energy systems, allow consumers to produce energy and sell it back to the grid. 

Mr. Chairman, based on the testimony that we will hear today, 

it appears there are some real concerns with Order 1000, and 

modifications may be needed to help meet its objectives. If the goal 

was to provide a clear and collaborative inter- and intraregional 

planning process, with transparent and fair cost allocations, in 

order to spur additional competition and increased investment in 

grid infrastructure projects, then it is less clear if that objective 

had been achieved. 

While most of the witnesses believe that changes should be 

made, there is less consensus on what those changes should look 

like. 

So I look forward to engaging the panel today, Mr. Chairman, regarding the opportunities and the challenges surrounding Order 

1000, as well as recommendations for improving this policy. 

With that, I yield back. 

Mr. OLSON [presiding]. Thank you. 

The chairman of the full committee, Mr. Walden, is not here. So 

the chair now calls upon the ranking member of the full committee, 

Mr. Pallone, for a 5-minute opening statement. 

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

Mr. PALLONE. Thank you, Mr. Chairman. 

I want to welcome our excellent panel of witnesses. 

In particular, I am pleased we have Ralph Izzo, the President 

and CEO of PSE&G here today. Ralph and I have worked together 

and known each other for many years, and I value his opinion and 

appreciate the service that PSE&G provides to my constituents and 

to our State of New Jersey. 

The network of transmission lines are truly the backbone of the 

power system, and these transmission lines are critical to providing 

reliable electricity. But just like any large, conspicuous infrastructure project, transmission projects are rarely free from controversy. 

And in densely populated areas, such as we have in the Northeast, 

allocating space for any new infrastructure is often a challenge. 

The electricity sector is undergoing tremendous change. There 

are new technologies in growth and distributed generation. At the 

same time, demand for power has remained relatively flat. And 

there are new challenges of extreme weather and cybersecurity 

threats, along with increasing demand for the grid to be more flexible and responsive. And all these things require us to evaluate the 

policy tools that FERC is using to manage its evolution. 

We will hear a variety of opinions today about the degree to 

which FERC’s orders are helping or hindering investments in elecVerDate Nov 24 2008 13:48 Aug 08, 2018 Jkt 037690 PO 00000 Frm 00011 Fmt 6633 Sfmt 6633 I:\MY DOCS\HEARINGS 115\HEARINGS\115-127 CHRIS
6 

tric transmission. It is a challenge to get this balance right, so it 

is no surprise that stakeholders in this arena will have diverse 

opinions on how to improve these policies. 

If we look at the map of existing transmission lines across the 

country, it is hard for me to believe that we need a lot of new 

transmission. This is a very mature network. But since much of 

that network has been in place for decades, it is also a good bet 

that it needs to be upgraded and modernized. 

This is something that companies must consider when they are 

pursuing a transmission project. And a project in my own district, 

the Monmouth County Reliability Project proposed by FirstEnergy, 

is one example where there was no serious consideration given to 

nontransmission options that could make the area’s system more 

resilient and reliable. 

It was only through the diligent efforts of a group of my constituents called the Residents Against Giant Electric, or RAGE, that 

this expensive, unnecessary project is not moving forward. RAGE 

provided expert analysis demonstrating that transmission alternatives could be accomplished or an upgrade to the grid at a far 

lower cost to ratepayers and that these alternatives were never seriously considered. The administrative law judge who reviewed the 

case in Monmouth County agreed with that assessment. 

This project in my home district illustrates that there remains a 

bias to building transmission rather than using new tools. It is in 

the financial interest of transmission companies to build, especially 

when there are clear rules that allow them to recoup those investments. 

Determining if new transmission is needed must involve all 

stakeholders and be evaluated without bias. If, in fact, new transmission lines are needed, and in some cases they will be, then the 

project should go forward. But where new technology can provide 

a cheaper solution that is less disruptive to other businesses, existing infrastructure, and communities, we should ensure that those 

options are used. 

So, again, the rapidly changing environment we are in right now 

is both exciting and challenging. FERC’s efforts to address transmission challenges have been admirable but far from perfect. There 

have been and will continue to be missteps along the way that require adjustment and correction, perhaps even serious revision in 

some areas. 

And so I am hoping, Mr. Chairman, that this series of hearings 

is providing all of us with an opportunity to better understand 

where the greatest challenges remain. 

And, again, I want to thank all of our witnesses, including Ralph 

Izzo, for appearing today. I look forward to your testimony. 

I would yield back the balance of my time to the gentleman from 

California, Mr. McNerney. 

Mr. MCNERNEY. Well, I thank the ranking member for yielding. 

And as a cochair of the Grid Innovation Caucus, I am pleased to 

be part of this hearing. 

I thank the witnesses for their testimony and look forward to 

working with them to create what the Presidents of both parties 

have called the 21st century electric grid. 

7 

Congress needs to address the requirements of an evolving grid, 

including advances in technology, consumer adoption of distributed 

generation, and increasing cyber threats to this backbone of American industry. 

Just yesterday two bills sponsored by Congressman Latta and 

myself focused on cybersecurity passed the full committee. This 

hearing is an important corollary to those efforts. What investments should we be making? What regulatory regime should we be 

reviewing within FERC or otherwise? And what more should we be 

doing to modernize our grid? 

I look forward to working with each of you to develop practical, 

commonsense proposals to creating an advanced transmission system. 

And I yield back. 

Mr. OLSON. Thank you. 

And there are no more opening statements by members, so now 

it is the fun time. Our witnesses will have 5 minutes to give their 

brief presentations. I will work this from your right to your left. 

And make sure you hit the button and it comes on, and speak into 

the mic. 

We have a former commissioner of FERC, Mr. Tony Clark, who 

is now a senior adviser at Wilkinson Barker Knauer. 

You are up, Mr. Clark, for 5 minutes. 

STATEMENTS OF TONY CLARK, SENIOR ADVISOR, WILKINSON 

BARKER KNAUER, LLP; EDWARD KRAPELS, CEO, ANBARIC 

DEVELOPMENT PARTNERS; JENNIFER CURRAN, VICE PRESIDENT, SYSTEM PLANNING, MIDCONTINENT ISO; RALPH IZZO, 

CEO, PUBLIC SERVICE ENTERPRISE GROUP INC.; JOHN 

TWITTY, EXECUTIVE DIRECTOR, TRANSMISSION ACCESS 

POLICY STUDY GROUP; AND ROB GRAMLICH, PRESIDENT, 

GRID STRATEGIES LLC 

STATEMENT OF TONY CLARK 

Mr. CLARK. Thank you, Mr. Chairman, members of the committee, and Ranking Member Rush. My name is Tony Clark. I am 

a Senior Advisor at the law firm of Wilkinson Barker Knauer, 

which has offices here in D.C. and in Denver, Colorado. 

From 2012 to 2016, I had the honor of serving on the Federal Energy Regulatory Commission. Prior to that, I served 12 years as a 

commissioner and for part of the time as chairman of the North 

Dakota Public Service Commission. It is a particular honor to recognize my former colleague, Congressman Cramer, and a good 

friend of many years. 

My testimony today centers on a white paper that I recently authored entitled ‘‘Order 1000 at the Crossroads.’’ It offers my reflections on the order, the status of it, and where it might go from 

there. I have attached a copy of the paper as an appendix to my 

testimony. 

As way of background, Order 1000 was promulgated before I got 

on the Commission, not long before I got on the Commission, so I 

didn’t participate in that. But I did participate in the many compliance filings that came forward in the wake of the order. 

8 

The main thesis of my reflection is that, however well-intentioned the order is, in practice it is falling short of the lofty goals 

that it set. I suggest that with the passage of a better part of a 

decade since its adoption, now is an appropriate time for FERC and 

for Congress, through its oversight authority, to engage in a meaningful assessment of the order. 

The paper concludes that one of the paradoxical results of the 

rule has been that the major transmission projects that many of us 

thought might come out of Order 1000 actually came out of a preOrder 1000 world. And in the time spent since Order 1000 was promulgated, there really haven’t been a lot of tangible projects that 

have come through or empirical data to support the success of the 

order. The paper concludes that if FERC were to better tailor the 

rule, especially recognizing significant regional differences across 

the utility industry, it might have more efficacy. Put succinctly, we 

may today find ourselves in the position of having a rule that ensures significant compliance costs, but without a lot of demonstrable benefits coming out the other side. 

It is perhaps ironic that many of the most impactful transmission 

projects that I mentioned, such as in my home region the MISO 

Multi-Value Project, arose from that pre-Order 1000 world that I 

talked about. I suggest that the reason for this is multifold. Some 

of it is that regions, particularly those that were served by 

vertically integrated utilities, were already doing a fair amount of 

planning within their regions prior to the order. For those regions, 

Order 1000 replaced that collaborative bottoms-up process with a 

Federal top-down process where there is a fair amount of bureaucracy that is involved with it. And the name of the game is making 

sure that you are checking compliance checklists as opposed to actually bringing projects to fruition. 

Creating a Federal mandate on top of what was already previously happening with many regions has added time and complexity. And we have seen in some regions a lot of litigation with 

respect to the transmission projects. The electricity landscape has 

changed dramatically in terms of the resources, technology, and 

State policies that drive transmission decisions, both since EPAct 

05 and Order 890, which preceded Order No. 1000. And then finally, certain implementation decisions, such as how cost allocation 

is handled within regions, has altered transmission development 

models that were previously broadly accepted within a number of 

the regions. 

In short, even among those who are broadly supportive of Order 

1000, there seems to a widespread sense that something is amiss 

with it in terms of the underwhelming results that have come out 

of it. In light of this, I would argue that it is appropriate for policymakers to consider Order 1000’s future given its track record. My 

paper encourages industry conversations about ways that Order 

1000 could be streamlined across the board. 

While regional planning conversations may result in some benefits—and I would add there may be some benefit especially when 

talking about interregional projects where maybe not as much conversation had happened in the past—there may be ways to do it 

while repealing some of the more prescriptive aspects of the order. 

9 

Briefly, moving beyond Order 1000, I would offer that I think 

there are a number of regulatory policy calls coming up that could 

have a significant impact on how transmission infrastructure will 

be developed. FERC has significant decisions ahead it, dealing with 

issues like rates of return on transmission projects for jurisdictional rates, issues related to transmission incentives that FERC 

builds into its rate structure. 

And, finally, one of the big elephants in the room on transmission development is, as it is with pipeline development, it is 

very difficult to get infrastructure projects sited and brought 

through the construction phase because of multiple levels of sometimes bureaucracy and red tape that can block some of those permitting decisions. 

With that, I conclude my testimony. Thank you. I look forward 

to any questions you might have. 

[The prepared statement of Mr. Clark follows:] 

10 


30978.001

Testimony of Tony Clark 

Senior Advisor, Wilkinson Barker Knauer, LLP 

Before the Committee on Energy and Commerce Subcommittee on Energy 

United States House of Representatives 

May 10,2018 

Chairman Upton, Ranking Member Rush and members of the committee, my name is 

Tony Clark. I am a senior advisor at the law firm of Wilkinson Barker Knauer LLP, which has 

offices in Denver, CO and Washington, DC. From 2012 until2016, I served as a Commissioner 

of the Federal Energy Regulatory Commission. Prior to that, I served nearly 12 years as a state 

utility regulator in my home State of North Dakota. During my tenure as a state commissioner, I 

had the honor of completing a term as President of the National Association of Regulatory 

Utility Commissioners. 

My testimony today centers on a recent white paper I authored entitled "Order No. I 000 

at the Crossroads." It contains my reflections on the Order, its history and its status, now close 

to seven years after its adoption. I have attached the paper as an appendix to my testimony. 

Given my career background, which straddles both sides of the state-federal jurisdictional 

divide in energy policy, I have long been interested in the topic of electricity transmission policy. 

This is especially true coming from a region of the country which is rich in energy resources, but 

geographically distant to the nation's major load centers. 

By way of background, I would note that Order No. 1000 was promulgated shortly before 

I joined FERC, so while I did not participate in its drafting, I did have the opportunity to be 

involved with the many compliance filings that resulted in its wake. 
11 


30978.002

The main thesis of my paper is that however well-intentioned the Order, in practice 

today, it is falling short of its goals. I suggest that with the passage of the better part of a decade 

since its adoption, now is an appropriate time for PERC to engage in a meaningful assessment of 

Order No. 1000. The paper concludes that one of the paradoxical results of the rule has been that 

major transmission projects of the kind that many thought the Order would spur came out of a preOrder No. 1000 world. Meanwhile, the post-Order No. 1000 timeframe bas been marked by 

bureaucracy, but few tangible projects or empirical data to indicate success for the Order. The paper 

concludes that PERC should better tailor the rule, especially recognizing the significant regional 

differences across the utility industry. Put succinctly, we may today find ourselves in the position 

of having a rule that entails significant compliance costs but without attendant benefits. 

I surmise that part of this is the result of the lack of clear focus in the Order itself. Order 

No. 1000 never fully reconciled the tensions between its numerous goals. Some goals, like 

increasing transmission planning and investment for remote sources of generation, can conflict 

with other goals, like competitive developer reforms. Similarly, the Order's public policy goals 

may be inherently contradictory in the face of conflicting state public policies, including those 

policies that may discourage the building of transmission. 

It is perhaps ironic that many of the most impactful transmission projects (such as the MISO 

"Multi Value Projects) arose from a pre-Order No. 1000 world. I suggest that the reason for this 

is multifold: 

• Regions, especially those that are still served by vertically integrated utilities, were 

already doing a fair amount of regional planning before the order. For these regions, 

2 
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30978.003

Order No. 1000 replaced this collaborative, bottoms-up approach to transmission 

planning with a complex bureaucracy, where the name of the game is completing a 

compliance checklist that may not actually result in transmission development. 

• Creating a federal mandate on top of what was previously happening within many 

regions has added time, complexity and litigation to transmission development. 

• The electricity landscape has changed dramatically in terms of resources, technology and 

state policies that drive transmission decisions. Order No. 1000 was written in a postEnergy Policy Act of2005 world that may not have yet fully appreciated the impact of 

things like low-cost natural gas, a proliferation of state public policies that support 

generation outside of traditional markets, flattening demand growth, and increasing levels 

of distributed energy resource penetration. 

• Certain implementation decisions, such as cost allocation policies, have altered 

transmission development models that were previously broadly accepted within regions. 

In short, even amongst those who are broadly supportive of the original Order, there is a 

widespread sense that Order No. 1000 is underwhelming in terms of producing results 

commensurate with its costs. 

In light of this, I argue that it is appropriate for policy makers to consider Order No. 1000's 

future given its track record. 

My paper encourages industry conversations about ways that Order No. 1000 could be 

streamlined across the board. While regional planning conversations may result in some 

3 
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30978.004

benefits, there may be ways to keep those benefits without imposing the more prescriptive 

aspects of the order. This is especially true in the majority of all states where utilities continue to 

serve as vertically integrated monopolies. Furthermore, while my paper highlights that there 

may still be a philosophical rationale for Order No. 1000 in restructured regions of the country, I 

do note that even there, the implementation of the Order has raised concerns, which suggests a 

review in these regions is merited also. 

Moving beyond Order No. 1000, I would offer that I believe there are a number of regulatory 

policy calls that will be made in the near future that will have a big impact on how and whether 

transmission infrastructure will be developed. 

FERC has significant decisions ahead of it related to transmission returns on equity for 

federal jurisdictional rates. In addition, issues related to transmission incentives may be ripe for 

a review at the Commission, as are discussions about how to best utilize regulatory tools such as 

Construction Work in Progress (CWIP). 

Finally, transmission development continues to be a difficult endeavor at many levels of 

government. Siting and permitting of any energy infrastructure is complex and controversialand transmission lines have long been amongst the most challenging of these projects. While 

some attempts to streamline transmission siting have been made in recent years, bringing 

projects to fruition is still among the most difficult undertakings of energy delivery companies. 

4 
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Thank you for the invitation to be with you today. I look forward to answering any questions 

you may have. 

5 
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30978.006

Testimony of Tony Clark 

Senior Advisor, Wilkinson Barker Knauer, LLP 

Before the Committee on Energy and Commerce Subcommittee on Energy 

United States House of Representatives 

May 10,2018 

My testimony today centers on a recent white paper I authored entitled "Order No. 1000 

at the Crossroads." The primary conclusion of the paper is that the bureaucratic requirements of 

Order No. 1000 outweigh its benefits, and it should be reconsidered, especially in regions of the 

country with vertically integrated utilities. 

It is perhaps ironic that many of the most impactful transmission projects arose from a preOrder No. 1000 world. I suggest that the reason for this is multifold: 

• Regions, especially those that are still served by vertically integrated utilities, were 

already doing a fair amount of regional planning before the order. For these regions, 

Order No. 1000 replaced this collaborative, bottoms-up approach to transmission 

planning with a complex bureaucracy, where the name of the game is completing a 

compliance checklist that may not actually result in transmission development. 

• Creating a federal mandate on top of what was previously happening within many 

regions has added time, complexity and litigation to transmission development. 

• The electricity landscape has changed dramatically in terms of resources, technology and 

state policies that drive transmission decisions. Order No. l 000 was written in a postEPACT 2005 world that may not have yet fully appreciated the impact of things like lowcost natural gas, a proliferation of state public policies that support generation outside of 

traditional markets, flattening demand growth, and increasing levels of distributed energy 

resource penetration. 

• Certain implementation decisions, such as cost allocation policies have altered 

transmission development models that were previously broadly accepted within regions. 

• The order lacked a clear focus, and Order No. l 000 never fully reconciled the tensions 

between its numerous, sometimes conflicting, goals. 

In short, even amongst those who are broadly supportive of the original order, there is a 

widespread sense that that Order No. l 000 is underwhelming in terms of producing results 

commensurate with its costs. 
16 


30978.007

Order No. 1000 at the 

Crossroads: Reflections on the Rule Its 

Future 

Clark 

APRIL2018 

\\:ith thanks to my colltagucs Tvfichael Keegan and Robin T ;unt. 
17 


30978.008

I. Overview 

With the passage of the better part of a decade since its adoption, now is an appropriate time 

for the Federal Energy Regulatory Commission (FERC) to engage in a meaningful assessment of 

Order No. 1000. This paper concludes that one of the paradoxical results of the rule has been that 

major transmission projects of the kind that many thought the order would spur came out of a preOrder No. 1000 world. Meanwhile, the post-Order No. 1000 timeframe has been marked by 

bureaucracy, but few tangible projects. The paper concludes that FERC should better tailor the rule 

to certain predominantly restructured regions of the countty while substantially unburdening those 

regions for whom the compliance regime seems to have quickly reached a point of diminishing 

returns. 

II. Introduction 

If the success of a rule promulgated by FERC is measured solely by the amount of industty 

discussion and trade press coverage, then FERC Order No. 1000 has a rightful place in the 

pantheon of great Commission rulings. Yet today, few who follow the electricity industry would 

argue that Order No. 1000 comes close to having successfully achieved its stated goals in a fashion 

similar to previous FERC reforms like the unbundling of electric transmission or pipeline 

transportation. Put plainly, Order No. 1000, you're no 888 or 636. 

Why has Order No. 1000 in practice never 

matched its hype? Why is it that many of the biggest 

regional transmission buildouts, the type of projects 

that Order No. 1000 purportedly encouraged, 

happened prior to Order No. 1000, while the period 

since its promulgation has seen relatively little 

transmission development? In short, even its biggest 

proponents must agree that Order No. 1000 somehow 

missed the mark, or concede that at best, its impact 

has been underwhelrning. And with the benefit of 

hindsight, what lessons have we learned? That is the 

focus of this White Paper. 

After laying out the background of Order No. 

Order No. 1000 ... imposes 

bureaucratic planning 

requirements on the 

national transmission 

system, largely without 

considering that each 

region's needs, priorities, 

and processes are different. 

1000 and discussing the myriad of goals that the rule was meant to support, this paper identifies one 

of the major pitfalls of the rule: it imposes bureaucratic planning requirements on the national 

transmission system,' largely without considering that each region's needs, priorities, and processes 

are different. After reviewing some of the significant differences that exist between the regions and 

the changes that have occurred in the electric industty since the rule was promulgated, I ask, ''Where 

are we and where do we go from here?" 

1 Of course, Order No. 1000 is only applicable to the extent ofFERC's jurisdiction over the transmission of electric 

energy in interstate commerce. 
18 


30978.009

III. FERC Order No. 1000 Background 

FERC aficionados can feel free to skip this section, but in the interest of thoroughness, I 

provide the basics of Order No. 1000. FERC's own website offers a concise overview of the 620 

page order, its background and features of the rule. Rather than reinventing a summary, FERC's 

explanation is provided in its own words: 

Order No. 1000 is a Final Rule that reforms the 

Commission's electric transmission planning and cost allocation 

requirements for public utility transmission providers. The rule builds 

on the reforms of Order No. 890 and corrects remaining deficiencies 

with respect to transmission planning processes and cost allocation 

methods. 

Background 

On June 17, 2010, FERC issued a Notice of Proposed 

Rulemaking seeking comment on potential changes to its 

transmission planning and cost allocation requirements. Industry 

participants and other stakeholders provided extensive comment in 

response to the Notice of Proposed Rulemaking. The Commission 

received more than 180 initial comments and more than 65 reply 

comments. 

Planning Reforms 

The rule establishes three requirements for transmission planning: 

Each public utility transmission provider must participate in a 

regional transmission planning process that satisfies the transmission 

planning principles of Order No. 890 and produces a regional 

transmission plan. 

Local and regional transmission planning processes must 

consider transmission needs driven by public policy requirements 

established by state or federal laws or regulations. Each public utility 

transmission provider must establish procedures to identify 

transmission needs driven by public policy requirements and evaluate 

proposed solutions to those transmission needs. 

Public utility transmission providers in each pair of 

neighboring transmission planning regions must coordinate to 

determine if there are more efficient or cost-effective solutions to 

their mutual transmission needs. 

Cost Allocation Reforms 

The rul~ establishes three requirements for transmission cost 

allocation: 

Each public utility transmission provider must participate in a 

regional transmission planning process that has a regional cost 

allocation method for new transmission facilities selected in the 

2 
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30978.010

regional transnuss10n plan for purposes of cost allocation. The 

method must satisfy six regional cost allocation principles. 

Public utility transmission providers in neighboring transmission 

planning regions must have a common interregional cost allocation 

method for new interregional transmission facilities that the regions 

determine to be efficient or cost-effective. The method must satisfy 

six similar interregional cost allocation principles. 

Participant-funding of new transmission facilities is permitted, but is 

not allowed as the regional or interregional cost allocation method. 

Nonincumbent Developer Reforms 

Public utility transmission providers must remove from 

Commission-approved tariffs and agreements a federal right of first 

refusal for a transmission facility selected in a regional transmission 

plan for purposes of cost allocation, subject to four limitations: 

This does not apply to a transmission facility that is not 

selected in a regional transmission plan for purposes of cost 

allocation. 

This allows, but does not require, public utility transmission 

providers in a transmission planning region to use competitive 

bidding to solicit transmission projects or project developers. 

Nothing in this requirement affects state or local laws or 

regulations regarding the construction of transmission facilities, 

including but not limited to authority over siting or permitting of 

transmission facilities. 

The rule recognizes that incumbent transmission providers 

may rely on regional transmission facilities to satisfy their reliability 

needs or service obligations. The rule requires each public utility 

transmission provider to amend its tariff to require reevaluation of 

the regional transmission plan to determine if delays in the 

development of a transmission facility require evaluation of 

alternative solutions, including those proposed by the incumbent, to 

ensure incumbent transmission providers can meet reliability needs 

or service obligations. 

Compliance 

Order No. 1000 takes effect 60 days from publication in the 

Federal Register. 

Each public utility transmission provider is required to make 

a compliance filing with the Commission within 12 months of the 

effective date of the Final Rule. 

Compliance filings for interregional transnuss10n 

coordination and interregional cost allocation are required within 18 

months of the effective date. 2 

2 "Order No. 1000-Transmission Planning and Cost Allocation," FERC, accessed Mar. 24, 2018, 

https://www.ferc.gov/industries/electricfindus-act/trans-plan.asp. 

3 
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30978.011

A reader unfamiliar with much of the history and contemporary practice of the electric utility 

industry would be forgiven if, after reading this summary, s/he responded with a shrug. On its 

surface, it really doesn't look like much more than: 

• transmission regions (including independent system operators (ISOs) and regional 

transmission organizations (RTOs)) should be talking amongst themselves and with each 

other to rationally plan the electric grid; 

• regions should figure out how to pay for transmission; and 

• there should be an opportunity for non-incumbent utilities to build transmission. 

While the preceding description of the rule is accurate, as far as it goes, a 50,000 foot 

explanation of Order No. 1000 understates the more robust list of motivations that inspired it. 

Frankly, if those three points were all that Order No.lOOO sought to accomplish, one might think it 

could be done with something less than the thousands of pages of regulations that comprise Order 

Nos. 1000, 1000-A, 1000-B and the numerous subsequent regional compliance Orders. To better 

understand the policy environment that gave us the rule and its numerous subsequent compliance 

filings, a little more color commentary is needed. It helps explain why nearly seven years after the 

rule was adopted, multiple industry observers wonder why something seems amiss. 

IV. The Many Goals of Order No. 1000 

Depending on the audience and the person or group discussing the goals of the rule, the 

benefits of Order No. 1000 might variously be purported to be: 

• The rule is designed to support state or federal "public policy requirements" in 

electricity. It should be acknowledged that, however 

nebulous the term, "public policy requirements," in 

reality, it was often code for "supporting renewables." 

However nebulous the term 

"public policy 

requirements" in reality it 

was often code for 

It would be difficult, however, for FERC to just come 

out and say, "Order 1000 is promulgated to support 

politically advantaged renewables." The Federal 

Power Act does not work like that, and FERC would 

have been called on the carpet in the courts had it tried 

it. Nonetheless, the state public policy considerations "supporting renewables." 

referenced in Order No. 1000 were clearly aimed at 

expanding transmission to support things like state 

renewable portfolio mandates, not expanding 

opporturuttes for coal, nuclear or natural gas powered resources. Order 1000 

envisioned the building of big, interregional projects, or energy superhighways 

stretching from geographically distant, but renewable rich, areas to the nation's load 

centers. Even more amorphous is the notion of "federal public policy 

requirements." In the context of 2010, it would be reasonable to assume FERC 

might have written this in anticipation of the Obama Administration's imposing of a 

theretofore unstated national energy policy; in all likelihood driven by carbon 

emissions constraints. But that never came to pass and if the nation has a coherent, 

stated national energy policy that lasts beyond the predilections of any given 

presidential administration, it would be hard to identify it. 

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30978.012

• The rule is designed to break down the silos between utilities and amongst regions of 

the country. In many ways, this argument was part and parcel of the one preceding 

it. For example, many felt that FERC needed to facilitate the delivery of windgenerated energy from places like the sparsely-populated, wind-rich Upper Midwest 

and Great Plains regions (located in the MISO and SPP regional transmission 

organizations), to the Mid-Atlantic and Midwestern population centers located in the 

PJM Interconnection. To the degree silos needed to be broken down, it was because 

states and regions were looking to realize the benefit of moving power (presumably 

renewables) across broader geographic regions, or so the argument went. 

• The rule is designed to increase competition in . the transmission industry. By 

eliminating a federal right of first refusal for incumbent transmission providers to 

construct proposed transmission projects and requiting regions to have a formal 

planning (and often a competitive bidding) process for transmission projects, 

competition in transmission development would rule and consumers could benefit 

commensurately. 

• The rule is designed to help overcome the inherent tension between generation and 

transmission. This argument was particularly salient in restructured regions of the 

country where an incumbent merchant generator might have self-interested reasons 

to maintain the price separation availa:ble to a generator in an area with transmission 

congestion. 

In sum, if the following questions were asked of PERC: 

"Is the main purpose of Order No. 1000 to get 

more transmission investment or is it to increase 

competition in the transmission business? OR, is 

Order No. 1000 designed to overcome the potential 

self-interest of generators or is it to promote renewable 

generators? OR, is it designed to support individual 

state public policies or is it a federal initiative to 

increase regional planning conducted by the RTOs 

rather than by the individual state regulated utilities 

themselves?" 

The answer would seem to be an unequivocal 

''YES!" 

Therein lay some of the unresolved tensions 

within Order No. 1000 which differentiates it from 

prior FERC orders like 888 and 636. While, like Order 

No. 1000, Order Nos. 888 and 636 entailed hard 

regulatory choices, stakeholder arguments and 

If you like supporting state 

or federal public policy 

requirements (whatever 

they are or whatever 

divergent goals they might 

hold), competition, 

renewables, greater 

planning, articulated cost 

allocation principles, 

decreasing the power of 

incumbent generators; then 

you are in luck, because 

Order No. 1000 has a 

process for you! 

numerous complicated proceedings to implement them, FERC itself seemed to be pulling industry 

toward a fairly clear goal of what was to be accomplished under each of these seminal Orders. 

Such clarity and single-minded purpose escapes the grasp of Order No. 1000. The Rule is 

held in the eye of the beholder. If you like supporting state or federal public policy requirements 

5 
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30978.013

(whatever they are or whatever divergent goals they might hold), competition, renewables, greater 

planning, articulated cost allocation principles, decreasing the power of incumbent generators; then 

you are in luck, because Order No. 1000 has a process for you! 

V. Implementing Changes Nationally without Fully Appreciating Regional 

Differences 

Not only does Order No 1000's lack of focus create internal tensions within the rule itself, 

but these tensions are then superimposed on an electric industry that is highly regional in polity and 

practice; and these are factors that Order No. 1000 has little ability to accommodate; though 

through its implementation, it does its best to avoid acknowledging this reality.' 

A. Order No. 1000 in Regions with Vertically Integrated States in Traditional Bilateral Markets 

One of my own "lightbulb" moments as it related to this issue was in contemplating how 

little sense the full Order No. 1000 compliance regime made in a state like Florida. I hope readers 

will pardon me if I quote from my own separate statement attached to the 2013 Florida compliance 

order: 

. . . this filing raises in my mind certain broader concerns 

regarding the general direction Order No. 1000 takes us in relation to 

non-market, non-RTO/ISO regions. 

As I have previously written, there is 

much I can ftnd worth supporting in 

I cannot help but ask if the 

bureaucracy imposed by 

CJrderlVo.1000may 

outweigh the benefits to be 

gained. 

Order No. 1000 and some of the 

subsequent compliance ftlings. 

Facilitating cost-effective transmission 

solutions, encouraging regional 

planning to meet customer needs and 

ensuring fair cost allocation are worthy 

endeavors. Greater standardization of 

those efforts would seem to hold a 

good deal of potential, especially in 

those regions of the country that have already voluntarily organized 

themselves into functioning RTOs and ISOs. But Order No. 1000 

may not ftt quite as well in certain regions of the country. Florida is a 

prime example. 

Order No. 1000 seeks to ensure that transmission projects are 

planned in a cost-effective manner and in such a way that public 

policy goals are met. In highly integrated regions, where there is 

3 In the spirit of full disclosure, this has long been a topic about which I have expressed a degree of concern. While 

I was not a member ofFERC when Orders Nos. 1000 and 1000-A were adopted (and was recused from Order No. 

1000-B), I did have the opportunity to review and vote on the many regional compliance orders that were filed 

during my term on the Commission (2012-2016). While individual regions had some degree of flexibility to tailor 

their compliance filings, that flexibility often seemed to me a bit illusory. 

6 
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30978.014

central dispatching, locational marginal pricing, and numerous state 

public policies that support geographically remote sources of 

generation, Order No. 1000 seems a reasonable effort to ensure just 

outcomes. 

But in a region like Florida, I cannot help but ask if the 

bureaucracy imposed by Order No. 1000 may outweigh the benefits 

to be gained. 

The FERC jurisdictional utilities that serve Florida are 

vertically-integrated, monopoly utilities whose planning and 

operations are comprehensively regulated by the State of Florida. 

Integrated resource planning and facility siting, as approved by the 

state, ensures that generation and transmission decisions are viewed 

and approved holistically. The Florida utilities' integration with the 

rest of the greater southeast region is limited physically due to 

Florida's unique geography. There is no central dispatching entity 

and no LMPs to reflect local congestion. Florida utilities have 

exercised their right to retain control of their transmission by not 

choosing to join an RTO/ISO. The Florida Parties state that there 

are no identified public policy requirements driving regional 

transmission needs. Thus, in large part, the rationale for Order No. 

1000 is lacking in Florida. 

Therefore, I am not entirely sure what is accomplished by 

Order No. 1000 in such a region. On one hand, since a good deal of 

integrated resource planning is already happening, there is a chance 

the real net effect of these changes will fall somewhere between 

minimally and modestly beneficial. But I fear by shoehorning Order 

No. 1000 into a region with existing and extensive state-led planning, 

we could risk the creation of an expensive, potentially litigious, and 

time-consuming additional layer of unnecessary bureaucracy. If this 

happens, the counter-productive result will not be more costeffective and timely built transmission, but less.4 

At the risk of appearing self-congratulatory, 

these concerns from 2013 have been largely realized in 

the non-RTO, bilateral market regions of the country.' 

Though I am unaware of a comprehensive study of the 

total costs of Order No. 1000 implementation, if 

anecdotal discussions with industry participants are any 

guide, initial and ongoing compliance expenses are 

greater than immaterial. 

As to the benefits, one would be hard pressed 

One would be hard pressed 

to point to concrete Order 

No. 1000 successes in 

bilateral market regions of 

the country. 

4 Tampa E/ec. Co., eta/., 143 FERC 1! 61,254 (2013) (Clark, Comm'r, concurring). 5 For purposes of the white paper I use the terms like bilateral market regions, and non-RTO, non-organized market 

regions to differentiate them from those regions of the country that operate within FERC jurisdictional, organized, 

centrally-dispatched energy markets such as those served by SPP, CAISO, MISO, PJM, !SO-New England and the 

New York-ISO. 

7 
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30978.015

to point to concrete Order No. 1000 successes in these bilateral market regions of the country. No 

doubt some good has come from the mandate that regions do a more systematic job of planning 

and determining cost allocation principles, but one would struggle to pinpoint major 

accomplishments that were not already being achieved through the traditional state-led regulatory 

processes that oversee the vertically integrated utilities that exist in these bilateral market regions of 

the country. 

To once again juxtapose Order Nos. 888 and 636, one of the reasons those rules have had 

greater impact and staying power was that FERC focused its reforms on areas in which its regulatory 

jurisdiction was more comprehensive-the terms and conditions of interstate electric transmission 

and natural gas transportation service. In contrast, Order No. 1000 occupies that blurry space at the 

intersection of state and federal policy. While FERC has undisputed authority over wholesale 

electric rates and over rate setting and cost allocation for interstate transmission service, Order No. 

1000 closely intersects with areas that are just as clearly within state jurisdiction: integrated resource 

planning, resource adequacy, transmission certification and siting, not to mention state public policy 

goals that promote various forms of energy generation. Given all that, it is little wonder the impact 

of Order No. 1000 on actual transmission planning and construction has proved most ineffectual in 

those regions of the country where states have maintained the greatest degree of regulatory 

authority. 

B. Order No. 1000 in Regions with Vertically Integrated Utilities in Organized Markets 

The foregoing discussion is 

Order No. 1000's mismatch 

is most glaring ... anywhere 

states continue to exercise 

their oversight of the 

traditional vertically 

integrated utility business 

model, whether in an 

organized market or outside 

of one. 

not to suggest that Order No. 1000 has conversely been a 

rousing success in the organized market regions of the 

country, only that the Rule's ineffectiveness has been 

most pronounced exactly where you would expect: 

where state authority is still most comprehensive. 

In my statement on the 2013 Florida 

compliance filing, I directed my suspicions about the 

efficacy of the Order No. 1000 planning regime, in 

part, towards those regions of the country that did not 

have an organized dispatch market, mentioning as a 

distinguishing characteristic, ''There is no central 

dispatching entity and no LMPs to reflect local 

congestion. Florida utilities have exercised their right 

to retain control of their transmission by not choosing 

to join an RTO/ISO."' 

This point is critical in understanding one of those underpinnings of FERC's Order No. 

1000 rationale: the tension between generator self-interest and the impact of transmission planning. 

And while the point is valid, in retrospect, I think I drew the distinction in the wrong place. 

Specifically, Order No. 1000's mismatch is most glaring not just in regions outside of organized 

markets, but rather, a'!Ywhere states continue to exercise their oversight of the traditional vertically 

integrated utility business model, whether in an organized market or outside of one. 

6 Tampa Elec. Co., eta/., 143 FERC, 61,254 (2013) (Clark, Comm'r, concurring) at 2. 

8 
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30978.016

Over the years, I have come to appreciate that the primary distinguishing characteristic 

between different electric utility regulatory ecosystems is how each state chooses to sttuctute it. In 

this light, I postulate that an Xcel Energy in MISO and a Dominion Energy in PJM share more in 

common with a. Florida Power & Light in Florida, than any of them share with a fully unbundled 

Exelon operating in a restructured state like Pennsylvania. 

This only makes sense. Much like the example of Florida utilities planning distribution, 

generation and transmission holistically for a region (with the oversight of the state), vertically 

integrated utilities within an organized market undergo a similar planning process. It's just that in 

the day-ahead and real-time energy markets their units are centrally dispatched by an independent 

market operator. This is far different than in restructuted states, where only distribution operates as 

a monopoly, and transmission and generation operate independently of each· other, with wholesale 

administrative market mechanisms established by FERC to help inform the business decision 

making process of merchant operators. 

With this understanding, it should come as little surprise that the unimpressive effects of 

Order No. 1000 on the organized markets in the vertically integrated regions of the country mirror 

the effects on regions outside of the organized markets. 

SPP and MISO offer two real-world examples of the pitfalls of Order No. 1000 in practice. 

Dating back to my time as a member of the North Dakota Public Service Commission, I had 

a pretty good sense of what I thought Order No. 1000 was trying to accomplish. It looked and 

sounded an awful lot like what we had already been doing, but with an overlay of additional FERC 

compliance burdens. 

From 2008-2010, I was a member of an. 

initiative started by the Governors of the States of 

Iowa, Minnesota, North Dakota, South Dakota and 

Wisconsin, known as the Upper Midwest 

Transmission Development Initiative (UMTDI). Like 

nearly all other states in MISO, these are all vertically 

integrated states. While each state had its own reason 

for joining, the collaboration helped vet a series of 

transmission projects that seemed to establish a 

baseline of "no regrets" lines that met the needs of 

each state. 

OrderNo.lOOO ... looked 

and sounded an awful lot 

like what we had already 

been doing, but with an 

overlay of additional FERC 

compliance burdens. 

The work of UMTDI dovetailed with other regional efforts like the "Cost Allocation and 

Regional Planning" process and the utility-driven CapX2020 initiative, which provided various levels 

of support for plans that all eventually funneled into a suite of broadly acceptable transmission 

projects that became known as "Multi-Value Projects" (MVPs). The MVPs were approved by MISO 

and integrated with its transmission planning process, and ultimately upheld by both FERC and the 

courts. As the name suggests, these projects served multiple needs. They displayed shared 

characteristics of reliability lines, market efficiency lines and lines that supported various state public 

policies. 

9 
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30978.017

These efforts were bottom-up, inclusive, cognizant of state public policy initiatives, and 

successful in getting a lot of needed ttansmission built. It was also done before FERC Order No. 

1000. 

In a similar way, the SPP region (another region made up of vertically integrated utilities) had 

successfully ushered in a series of reforms through its highway-byway model prior to Order No. 

1000. 

Yet since the rule has been promulgated, much of this type of transmission activity has 

slowed to a crawl in the very regions where it had previously been most robust. While some of this 

may be attributed to flattening electricity load growth, and the fact that these projects alleviated 

some of the pent-up need for additional transmission projects, I would suggest that an ossified and 

bureaucratic Order No. 1000 planning process actually stifles what was previously happening 

organically. Insofar as this is true, it would indicate Order No. 1000 has not just been ineffective in 

certain regions of the country, it is actually counterproductive. 

It is in regions where vertically integrated (and state-regulated) utilities partl.opate in 

organized markets that we can see most clearly the effects of Order No. 1000's series of unresolved 

and sometimes contradictory goals. If the rule's goal was to incorporate state public policy planning 

and establish cost allocation certainty in order to build ttansmission, then these regions were already 

doing that. 

Yet these regions were admittedly not at the forefront of prioritizing the injection of nonincumbent transmission competition into the planning process because, frankly, the concept has 

limited value and appeal in a region where the states themselves have determined that they prefer the 

regulated, vertically integrated utility ecosystem.' In addition, FERC's insistence that even one 

We have been left in, 

arguably, a worse position 

than where we began: more 

process, more compliance, 

more delay, more 

paperwork, more planning; 

less transmission actually 

being built. 

penny of regional cost allocation ended an incumbent 

transmission owner's federal right of first refusal 

caused a series of cost allocation methodologies that 

previously had garnered widespread acceptance to fall 

apart. 8 

In short, at least within MISO and SPP, the 

two RTOs that are most representative of joint 

dispatch markets composed of vertically integrated 

utilities, Order No. 1000's pro-non-incumbent 

"competition" goals ran headlong into its state public 

policy and pro-transmission investment goals. We 

have been left in, arguably, a worse position than 

where we began: more process, more compliance, 

more delay, more paperwork, more planning; less transmission actually being built.' 

7 Indeed, a number of states continue to assert a state right of first refusal, further emphasizing this point. 8 See Midwest Indep. Transmission Sys. Operator, Inc., 142 FERC 1!61,215 atP 518 (2013); see also Southwest 

Power Pool, Inc., 144 FERC 1!61,059 (2013) (Clark, Comm'r., dissenting in part, noting MISO's elimination of 

regional cost allocation fur Baseline Reliability Projects so as to retain a federal right of first refusal for such 

projects; see Southwest Power Pool, Inc., 149 FERC 1!61,048 (2014) (Clark, Comm'r, dissenting in part). 9 Beyond the scope of this paper is a comprehensive analysis of how Order No. 1000 is unfolding in each distinct 

region of the country. Sagas like the PJM Artificial Island project will prove instructive as to the promises and 

10 
27 


30978.018

VI. The Times They Are A Changin' 

In a turbulent era, Bob Dylan reminded the world that "The Times They Are a Changin'."10 

So, too, have there been a lot of changes in the electric industry since the Order No. 1000 

rulemaking process started in 2010. 

Order No. 1000 has its roots in the transmission planoing principles FERC established in 

2007 in Order No. 890 and was influenced by the Energy Policy Act of 2005's (EPAct 2005) 

emphasis on reinforcing the transmission system and encouraging the construction of new 

transmission facilities. In 2007, gas prices were high and growth in electric energy usage seemed 

limitless. Transforming the transmission system, or at least building it out, would be necessary to 

bring renewable energy resources online that could satisfy the country's appetite for electricity and 

wean the nation off of natural gas. As I describe above, regional transmission planoing was already 

underway before FERC promulgated Order No. 1000. Numerous multi-region high voltage 

transmission projects-the type that seemed to be the goal of rule-were being developed by the 

time FERC issued its proposed rule in 2010. 

Now that the rule has been promulgated and 

the planning processes have been formalized, where 

are the projects? 

A lot has changed since the Order No. 1000 

rulemaking process was begun in June 2010 -

flattened demand, increased reliance on cheap 

natural gas, increased energy efficiency, and the 

growth of demand response and distributed 

generation. The combined effect of these and other 

changes may have made multi-state superhighway 

transmission projects less viable (and less necessary 

in order to satisfy state or national policy goals). 

Order No. 1000 was designed to address problems 

A lot has changed since the 

Order No. 1000 rulemaking 

process was begun in June 2010 

-flattened demand, increased 

reliance on cheap natural gas, 

increased energy efficiency, and 

the growth of demand response 

and distributed generation. 

that existed when Order No. 890 was being implemented, and to facilitate the goals of EP Act 2005. 

The Order remains, but the problems it was designed to address, to the extent they were truly 

problems, have largely gone away or transformed themselves. 

VII. Where Are We and Where Do We Go from Here? 

If it is true, as psychologist Nathaoiel Branden said, that "the first step towards change is 

awareness," then Order No. 1000 may be ripe for a reassessment." There seems to be a growing 

number of individuals aware that the rule has missed its target, or targets, as it were. 

pitfalls of Order No. 1000 compliance. On the plus side, PJM has identified a potentially cost saving project, but 

challenges have abounded: disputes over the project selection process, internecine strife amongst states based on 

cost allocation decisions, and difficulties for the RTO itself, which has become much more of a project development 

manager than it probably ever intended or hoped. 10 Bob Dylan, The Times They Are A Changin ',THE TIMES THEY ARE A CHANGIN' (Columbia 1964). 11 In 2016, ScottMadden published a whitepaper that examined the effectiveness of Order No. 1000, stating "it is 

useful to assess whether the industry has achieved competitive processes as originally intended. While opinions vary 

11 
28 


30978.019

Unfortunately, there is less agreement about what to do about it. The camps basically break 

into three, and view the current status of Order No. 1000 as either: 

A. A fundamentally sound idea that is making painfully slow progress towards some goals, but 

not others, such as large interregional transmission projects; or 

B. Something that may not ultimately accomplish a lot, but it seems to encourage some 

laudable things; or 

C. Proof of the law of unintended consequences; a rule, as currently constructed, that is 

generating more costs than benefits. 

What you think should be done to change the rule is ultimately dependent on which camp 

you fall into. 

For those who see the rule as generally described in proposttton "A" there will be a 

temptation to double-down on Order No. 1000's most prescriptive aspects. If new projects aren't 

being built, it must be because incumbents and states have dug-in their collective heels, goes the 

theory. They are gaming whatever flexibility was provided in the original compliance filings so it is 

time to tighten the screws. Less flexibility is the answer and let us drive Order No. 1000 deeper and 

deeper into the grid. Let's drive it down to lower voltages. Let's make sure those projects don't 

escape our planning processes by popping up as thinly veiled "reliability projects." 

Let us call this approach, "the beatings will continue until morale approves!" solution. 

I strongly urge that we avoid this path. 

If the goal is to make sure that even less gets built than under "Classic Order No. 1000," 

then this is would be the way to accomplish it. Order No. 1000's requirements have changed the 

goals of transmission planning. Before the rule, the purpose of the planning processes was to 

identify necessary improvements in electric energy infrastructure. The imposition of Otder No. 1000 

has created a new litmus test for success: identifying projects that can satisfy the rule, particularly a 

project that is eligible for interregional cost-sharing. 12 

As I describe earlier, Order No. 1000's requirements are oftentimes redundant to preexisting state regulatory schemes for vertically-integrated utilities, simply adding an unnecessary layer 

of regulatory process. Expecting regions and RTOs, which are already struggling under the weight of 

their existing regional and interregional planning processes, to impose said process even further 

down to the next level on the grid invites even more stagnation and death by bureaucracy. All of the 

unresolved internal conflicts with the divergent goals of Order No. 1000 that I have written about 

by stakeholder and region, we believe the answer to this question is a resounding 'no.'" Cristin Lyons and Brian 

Messick, FERC Order No. 1000: Five Years On, June 2016, at 3, available at htto://www.scottmadden.com/wpcontent/uploads/2016/06/Scot!Madden FERC Order 1000 2016 060l.pdf. 12 As an aside, it's interesting that a transmission project located entirely in Missouri might cross through multiple 

regions, and, therefore, be a success under Order No. 1000 interregional planning; but a transmission project that 

would run the length of the Mississippi River could be located entirely in the MISO region, and, therefore, worthy of 

no particular merit under the rule. 

12 
29 


30978.020

become more problematic at this level. This change wouldn't alleviate Order No. 1000's problems, 

it would exacerbate them. 

Those who fall into camp ''B," "Order 1000 may not ultimately accomplish a lot, but it 

seems to encourage some laudable things" are the most status quo oriented of the bunch. They are 

probably aware that the rule is not working as intended, but are cautious by nature, and think that 

any problems should be addressed incrementally. Their argument might be: At the very least, letting 

the rules collect a bit more dust wouldn't seem to do much harm while we give Order No. 1000 

more time to mature. People who fall into this camp may also be of the opinion that Order No. 

1000 is actually doing more harm than good, but they are concerned that once FERC begins 

tinkering with it, they might end up with something worse: better the devil you know than the devil 

you don't. 

Finally, are the people who are in camp 

"C," those who have come to the conclusion that 

no matter how well-intentioned the rule, the 

cumulative weight of it can no longer be justified 

by its results, or lack thereof. Count me among 

their number. 

Even within Camp C, no doubt, there is a 

variety of opinion on what to do about the failed 

Order. "Be done with it already" is certainly one 

path, and given the paucity of hard data that 

No matter how well-intentioned 

the rule, the cumulative weight 

of it can no longer be justified by 

its results, or lack thereof. 

supports Order No. 1000's efficacy, and the difficulty in evaluating what data exists, it would be an 

understandable response." However, realists about government action have to acknowledge that 

history is not replete with examples of government regulatory agencies on their own "calling a 

mulligan" and dismantling a regulation of Order No. 1000's scope. 

VIII. The Order No. 1000 Reboot 

My suggestion is for FERC to step back and reassess Order No. 1000's key goals and adjust 

accordingly. 

The "supporting public policy requirements" goal, while a nice sounding bumper sticker, 

fails in practice. State policies, to the degree they happen in vertically integrated states, are already 

self-supporting through state-led resource adequacy and integrated resource planning that has gone 

on for years. In restructured states, goals and requirements have been shifting rapidly in recent 

months, as state governments in such places as diverse as Illinois, New York, New Jersey, 

Massachusetts and Connecticut devise around market actions to prop-up ailing and politically 

favored generators. At the Federal level, to the degree the nation has public policy requirements 

that would establish a national energy policy; they are vague, at best. As previously noted, there is 

no stated national energy policy. To the degree there is an implicit energy policy guided by 

13 See, e.g., Federal Energy Regulatory Commission, 2017 Transmission Metrics: Staff Report, Oct. 6, 2017 at_, 

available at https://www.ferc.gov/legal/staff-reports/2017/transmission-investment-metrics.pdf. The StaffReport 

notes that "it is difficult to assess whether the electric industry is investing in sufficient transmission infrastructure to 

meet the nation's needs and whether investments made are more efficient or cost effective." Id at 6. 

13 
30 


30978.021

Presidential ambitions, in the last 18 months it has shifted from an administration for whom GHG 

policy was the overriding factor to one that emphasize energy dominance, security and economic 

development. Given the nature of these competing state and federal energy visions, it would be 

better for FERC to step away from this aspect of Order No. 1000. At most, a FERC requirement 

that that utilities located in the same and adjacent regions compare notes and plan for efficiencies 

should be more than enough to deal with this matter. 

Eliminating the public policy requirements goal also has the benefit of discarding one of the 

thornier problems embedded in Order No. 1000. When state goals come into conflict (e.g., state A 

has a particular flavor of an RPS, state B does not, and would like to support its own native 

generation, thank you very much), who decides which state's requirements are valid? The planning 

region? The RTO? FERC? 

Even in regions that might support some of the competition goals of Order No. 1000, the 

public policy requirements goals sound better on 

paper than in practice. Take for example, recent 

Given the nature of these 

competing state and federal 

energy visions, it would be better 

for PERC to step away from [the 

Public Policy] aspect of Order 

No.1000. 

efforts in New England to build transmission 

from Canada for access to Canadian hydro. The 

region is predominantly restructured. 

Massachusetts has a state public policy to use 

more hydro power. But New Hampshire does 

not, and has shown no intention of allowing a 

transmission line to be sited through it for the 

benefit of Massachusetts energy priorities. 14 

FERC rules or not, there is nothing in the Federal 

Power Act that resolves that situation. And 

multistate RTOs are not in a position to pick which state's policy should take precedence over that 

of another state. 

So if we take out the canard of supporting state and federal public policy requirements, what 

are we left with? I would suggest that a potential nugget within FERC Order No. 1000 that bears 

ongoing consideration is related to the notion that in certain restructured regions of the country, 

there is a potential disconnect between transmission planning decisions and generation/ market 

decisions. Issues related to the changing generation portfolio, the desire for fuel diversity, and effects 

of low gas prices and the growth of renewables are related to the challenges of transmission 

congestion reduction. The way to address these related concerns is to require transparent regional 

transmission planning, interjected with the ability of non-incumbents to compete for those projects. 

But here is the rub; that problem statement should not be addressed through nationwide fiat, 

but rather as a rule primarily targeted towards "Restructured Administrative Markets."15 

14 See: http://www.unionleader.comlbusiness/masschusetts-drops-northem-pass-bid-in-favor-of-rival-project--

20180328 

15 That is to say, NY-ISO, PJM and ISO-NE, See Clark, Tony, Regulation and Markets: Ideas for Solving the 

Identity Crisis. July 2017, available at http://wbklaw-com.securec23.ezhostingserver.com/uploads/file!Articles-

%20News/20 17%20articles%20publications/Market"/o20Identity%20Crisis%20Final%20(7 -14-17).pdf. 

14 
31 


30978.022

If PERC more clearly targets Order No. 1000 to address this issue, then it need not impose 

the requirements on those regions where they make little sense. If that sounds somewhat familiar, it 

should, because it is essentially the policy call PERC made when it only approved capacity markets 

for regions of the country that had substantially restructured. For all of the problems and 

controversies that exist with capacity markets, at least it can be said that PERC has tacitly 

acknowledged that they only seem to have a role where the structural characteristics of the market 

fit. 

If only PERC would make such an acknowledgment in the Order No. 1000 planning space, 

much of the Order No. 1000 conundrum could be avoided. It could accomplish this by targeting 

the bulk of the Rule to the Eastern Capacity Market regions of the country, while substantially 

repealing or reducing it in those areas where it is less justified, and which were inarguably meeting 

much of the spirit of Order No. 1000 prior to its imposition. 

IX. Conclusion 

PERC Order No. 1000, for all its good intentions, is today a rule that has largely fallen short 

of accomplishing its goals. Unfortunately, the failure of it to fulfill its potential has not come 

without costs. Given the changes in the electricity industry over the last decade, now is a good time 

for the Commission to consider an Order No. 1000 reassessment. PERC would do well to ask, 

''What are we really trying to accomplish?" and then tailor the rule narrowly to achieve those goals. 

Clinging to an increasingly odd fitting rule in the face of growing evidence that it is not working will 

only increase the difficulty of reforming it when that time eventually comes. 

15 
32 

Mr. OLSON. Right on time. Thank you, Commissioner Clark. 

Our next witness is Dr. Edward Krapels. 

Mr. KRAPELS. Perfect. Thank you. 

Mr. OLSON. CEO of the Anbaric Development Partners. 

Five minutes, Dr. Krapels. 

STATEMENT OF EDWARD KRAPELS 

Mr. KRAPELS. Thank you, Mr. Chairman and distinguished members of the Energy Subcommittee. 

My name is Ed Krapels, and I am the founder and CEO of 

Anbaric, which is an independent transmission microgrid storage 

and smart energy campus developer. We are funded by institutional investors, so we are not your typical utility. 

We like to think we build the electric businesses of the future, 

and the future is very different from the past, as other members 

have already indicated. We helped to spearhead two high-voltage 

direct current buried transmission lines between New Jersey and 

New York. The high-voltage direct current technology is common 

worldwide, but not widely used yet in the United States. 

As a person who has actually developed interregional transmission projects, I have taken the opportunity to write an article 

that is part of my prepared testimony that was just published in 

The Electricity Journal called ‘‘Triple Jeopardy.’’ It reviews why, 

even though everyone agrees these kinds of interregional transmission links are useful and that more are needed, both existing 

and new interregional projects are being choked off by well-intentioned but unproductive regulations. 

Some of these stem from Order 1000 and the inability to implement Order 1000 in a way that is sufficiently prescriptive to handle 

the many issues that arise when interregional transmission 

projects are proposed. 

I am here this morning, however, to discuss a really important 

new opportunity in our power industry. Federal energy and environmental policy can accelerate what promises to be a once-in-ageneration chance to launch a new domestic industry, and that is 

offshore wind, if we do it smartly and thoughtfully from the start. 

The key to success is to plan, design, and build shared independent offshore transmission, OceanGrids, in a thoughtful way in 

each of the participating coastal States. The Federal Government 

obviously has a huge role in this through the BOEM and FERC 

procedures that have to be implemented as part of this plan. 

Why are these planned and independent OceanGrids so important? Because after years of development in Europe, technology has 

pushed the price of offshore wind down to super-competitive levels. 

With that, American offshore wind is now a natural component in 

the administration’s energy dominance strategy. It is indeed fuel 

from heaven, and its time has come. However, as with all largescale energy resources, indeed with any important new industry, 

the business, financial, and physical platform on which it is built 

must be carefully designed and developed. 

Unfortunately, some ideas about offshore wind would jeopardize 

the ability to realize its full potential. Early policy proposals in 

Massachusetts, New York, and New Jersey explicitly would give 

generators the exclusive ability to own the transmission lines that 

33 

take offshore wind to market. These proposals have been promoted 

by giant, largely European wind developers that would get America’s offshore undertaking off on an anti-competitive and wrong 

footing. It is obviously in their interest to control as much of the 

access to the onshore grid as possible. If we allow that to happen, 

we will lose the kind of competition that will further lower offshore 

wind prices. We will lose more fishing grounds because there are 

more subsea cables than necessary. We will lose control over a substantial portion of our own coast. A proliferation of cables would 

displace and distress marine life during construction and operations and make it hard to avoid estuaries and navigate sensitive 

shoreline points of entry that will undermine an industry in a vital 

period of its growth. 

We are proposing in our OceanGrids a smaller number of large 

collector stations that are placed at the edges of the offshore wind 

farms, gathering the electricity from multiple wind farms and 

bringing it to shore via the minimum number of transmission cables buried in the seabed. These cables would be buried under the 

ocean floor and sized for multiple wind projects, and it could be either direct current or alternating current, depending on the distance to shore. 

If we do it right, we will create an industry and tens of thousands of 21st century jobs. We will create competition between generators. And it is that competition that will bring the price of offshore wind down to market levels. 

I will close by saying that in Europe today offshore wind auctions 

are yielding prices of 4 to 5 cents per kilowatt hour, which is pretty 

close to the market price. 

Thank you very much. 

[The prepared statement of Mr. Krapels follows:] 

34 


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5/7/2018 11:30:31 AM 

TESTIMONY OF EDWARD N. KRAPELS, CEO OF AN BARIC DEVELOPMENT 

PARTNERS, BEFORE THE ENERGY SUBCOMMITTEE OF THE HOUSE ENERGY AND 

COMMERCE COMMITTEE, MAY 10,2018 

Mr. Chairman, distinguished members of the Energy Subcommittee of the House 

Energy and Commerce Committee. Thank you for inviting me to testify on the 

State of Electric Transmission: Investment, Planning, Development and 

Alternatives. 

My name is Ed Krapels and I am the founder and CEO of An baric. We build the 

electric businesses ofthe future. We helped spearhead two high-voltage, direct 

current buried transmission lines between New Jersey and New York, increasing 

market efficiency and saving ratepayers hundreds of millions of dollars as a result. 

This high-voltage direct current technology is common world-wide but not used 

much in the US- its small size makes it well suited to linking markets in congested 

areas of the country where construction is difficult. An article I have just 

published in The Electricity Journal, reviews why-- even though everyone agrees 

these kinds of interregional transmission links are useful and more are needed--

both existing and new interregional projects are choked off by well-intentioned 

but unproductive regulations. That article is part of my written testimony. 

We come here this mor11ing, however, to discuss an extremely important new 

opportunity in our power industry. Federal energy and environmental policy can 

accelerate what promises to be a once-in-a-generation chance to launch a new 

domestic industry- offshore wind --if we do it smartly and thoughtfully from the 

start. The key to success is to plan, design and build shared, independent offshore 

transmission systems- OceanGrids- in each of the participating coastal states. 

Why are these planned and independent OceanGrids so important? Because, 

after years of development in Europe, technology has pushed the price of 

offshore wind down to super-competitive levels. With that, American offshore 

wind is now a natural component in the Administration's Energy Dominance 

strategy. It is indeed Fuel from Heaven, and its time has come. 

However, as with all large-scale energy resources-indeed, with any important 

new industry, the business, financial, and physical platform on which it is built 

must be carefully designed and developed. Unfortunately, some ideas about 
35 


30978.024

5/7/2018 11:30:31 AM 

offshore wind would jeopardize the ability to realize its full potential. Early policy 

proposals in Massachusetts, New York and New Jersey explicitly would give 

generators the exclusive ability to own the transmission lines that take offshore 

wind to market. These proposals have mostly been promoted by giant, largely 

European wind developers that would get America's offshore undertaking off on 

an anti-competitive, wrong footing. It's obviously in their interest to control as 

much of the access to the onshore grid as possible. 

If we allow that to happen, we will lose the kind of competition that will further 

lower offshore wind prices. We will lose more fishing grounds because there are 

more subsea cables than necessary. We will lose control over a substantial 

portion of our own coast. A proliferation of cables would displace and distress 

marine life during construction and operations, and make it hard to avoid 

estuaries and navigate sensitive shoreline points of entry. It will undermine an 

industry in a vital period of its growth. 

What we are proposing in our OceanGrid is a smaller number of large collector 

stations that are placed at the edges of the offshore wind farms, gathering the 

electricity from multiple wind farms and bringing it to shore via the minimum 

number of transmission cables buried in the seabed. These cables would be 

buried under the ocean floor and sized for multiple wind projects and it could be 

either the size I showed you earlier or this size. 

If we do it right, we will create an industry and tens of thousands of twenty-first 

century jobs. We will create competition between generators. We will create low 

power prices. And we will preserve the coast. Because we will create an industry 

here in America, we will increase and enhance our energy independence. The 

results: "zero-subsidy bids" from wind generators in the European countries 

which have followed the separate OceanGrid strategy. 

The slides at the end of my prepared testimony illustrate what's needed. It shows 

the New Jersey and New York coastlines, where almost 8,000MW of wind -

enough to power 4 million homes - will be built offshore in the coming decade. 

The first map shows where the designated wind areas are in relation to the 

coastlines of New Jersey and New York. The wind areas are in federal waters, and 

the ·power must be brought to shore in an efficient and environmentally sound 

manner. 
36 


30978.025

5/7/2018 11:30:31 AM 

The second map shows the effects of each 400MW wind farm building its own 

transmission lines to the coast. The third and fourth maps show the other cables, 

shipping lanes, ocean disposal sites, artificial reefs, unexploded ordinance, and 

other danger zones and restricted areas that impede the transmission cables 

paths to shore. 

Anbaric's OceanGrid proposal is shown in the last slide. Instead of 20 small cables, 

we envision 5 to 10 cables designed to carry the maximum amount of electricity 

per conduit. The plan can be executed in phases, and the technology can be 

adapted to the needs of the specific procurements that each state will conduct. 

America has a once-in-a-lifetime opportunity to create a new industry. Let's 

maximize the prospects of success from the start- with a thoughtful and farsighted approach to planned transmission that benefits taxpayers, electricity 

consumers, businesses, and our nation's economy. 

Ladies and Gentlemen of the Committee, as we welcome this important new 

offshore wind energy industry, let's dedicate ourselves to ensuring that the 

states, industry leaders, utilities and regulators, with appropriate Federal 

oversight, embrace the urgent need to build this critical new infrastructure in the 

right way from the start. 
37 


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5/7/2018 11:30:31 AM 

Anbaric's Proposed 

OceanGrids of New Jersey 

and New York 

Attachment to Prepared Testimony of Edward N Krapels, 

CEO of Anbaric, before the Committee on Energy and 

Commerce, U.S. House of Representatives 

MaylO, 2018 
38 


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5/7/2018 11:30:31 AM 
39 


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5/7/2018 11:30:31 AM 
40 


30978.029

SUPPLEMENT TO TESTIMONY OF EDWARD N. KRAPELS, CEO OF AN BARIC 

DEVELOPMENT PARTNERS, BEFORE THE ENERGY SUBCOMMITIEE OF THE HOUSE 

ENERGY AND COMMERCE COMMITIEE, MAY 10, 2018 

"Triple Jeopardy: How ISOs, RTOs, and incumbent utilities are killing interregional 

Transmission'/ 

By Edward N. Krapels 

To be published in The Electricity Journal 

May2018 
41 


30978.030

Contents Hsts available at SdenceDirect 

The Electricity Journal 

journal homep:age: www.elsevier.com 

Triple jeopardy: How ISOs, RTOs, and incumbent utilities are killing interregional 

transmission 

Edward N. Krapels1 

Anbaric Dewlopmem Partn<'.rs, 401 Edgewater PI, Suire 6HO, Wakefi'eld, MA, 01880< USA 

..... _ABSTRACT 

1. Summary 

cost 

The intt'rregional ·•planning" th<tt was promoted by the Obama-era 

FERC 

2. The first jeopardy: interconnection costs 

of ;my electric asset, the sponsor 

the transmission t.>ntity to \Vhich 

organized powt>r mflrkets, this an 
42 


30978.031

3, The second jeopardy: revenge of the urban generators 

incumbents. 

in HTPs case, the challenge ('ame in form of 

changes in NYISO's capacity regulations and iri the form of cost 

allocation "surprises" in the PJM To explain happened 

2010, 

review of how the NYISO works. Un· 

amendments <\nd refinements 

but FERC disposes approvals 

2 SF.<', for <-xamp!c, lnvestov.; an' BmldmgThcir Own Gr~en Power Unes," Russdl Gold, 

to33DMW 

would ultimately be called "market power mitigation mea5ures applkahle to the New York City (in-City) Installed Capacity (ICAP) market"5 

its effect, if not its intent, was to protPCt New York City generntors from 

C'nhancements to the transmission system. 

The originill regulations for the New York !SO's JCAP market created 

strktions. 

be 11rohib!ted troto ptnttctpa:tmg 

riod of yE'ars. 

of dollars per year in revenue. 

\Nhaten:•r one's opinion of this <'OP.Struct 

ate ev('n in pdndple - to apply tht> to new transmission lim•s. 
43 


30978.032

mission Ilne was puzzling. Simply stated, such a transmission line isn't 

a generator, nor ls it a ·'generator lead." By treating a tontrollable in· 

transmission line as if it W{'Xe a generator, the NYiSO simthe fundamental differences between generation 

lated transmJsston provider with a franchised service territory (i.e., a 

non-merchant transmission line) has market power by Yirtue of the 

fact that transmission is assumed to be a ''natural" monopoly. Consetransmission. Such an error isn't all that wmmon in line is provided under the terms of an ISO-RTO OATT, and it's therefore 

and here was perhaps more an art 

it's en·oneous to equate .agents of 

with agents of transportation {transmission), 

Transmission aren't generators. Generators create elertrkity; in~ 

and controllable transmission lines cnnvf'y 

ago 

commit what are now called category errors: "a category mistake arises 

when lhings or farts of one kind are pres('nted as if they belonged to an· 

It seems plain that the NYISO committed a category error when it 

looked upon Ifudson Transmission and assumed it was of the categO!)' rather than in the category 

that provides electric energy, 

l.'l.ry services from one 

tory, that it won't have the ability to exerclse market power (instead it 

tums operational control over to an ISO·RTO), and it can't engage 

in undue discrimination or affiliate i'.buse, FERC determined that Hudon IITP robbed the New 

its to serve as a conduit to the PJM capacity market. Ironically, in most parts of Amt•rka's vibrant and com~ 

ISO system. e\onomy. afflicted by the 

It's a high~tech, controllable, system-to·system connection between the third jeopardy. 

transmission service, and its costs for doing so are 

construction, r<Hher than lhe marginal costs of fueL 

and new transmission projeets are 

the concept the NYISO's mk-s, 

can't he- meaningfully applied to transmission lines:~ 

important, the PERC applies different standards to evah!-

4. The third jeopardy: revenge of the incumbent utilities 

In 201S, the NYISO's category en-or was amplified and compounded 

by the efforts of utilities on the PJM sid-e of the transmission line to 

extract hundreds of millions of dollars of additional costs on HTP, The 

Project was designed to prO\' ide a way for its nmomer- NYPA --to pm;-
44 


30978.033

The Elennrny Joumal x:o: (2018) xxx·x:o: 

ment with Consoildated Edison (t<llled '·the Wheel'').Il ConEd filed com- in Order 1000 and a new category of cost allocation for lnterreNew York-bound transmission lines, like llTP. The stakes in this RTEP 

allocation drama extremely high. Con Ed was assessed more than 

80% of the million for its lOOOMW wheel while PSEG with its 

load of ll,OOOMW WllS assessed only 7%. 

diSJJrot>m'liomlte allocation of hundreds of millions of dollars 

and PSEG to New York customers raised 

and viability of interregional transmission. 

filing to FERC noted that ''As a result, the HTP FfWRs-whkh 

lntt"nded to impart a beneficial and valuable right to the 

holdert>·-lravc not only be<'ome worthless, hut now represPnt a $645 

million liability that threatens the continued of tht' Hudson 

Transmission Project merchant 

to on m 

customers of the New York Authorities who believed they could 

rule-makings in the "power market next door." 

NYPA observed in its July 2017 filing, PSEG "is cl.Parly motivated by its 

fear that NYPA's ftlrrent RTEP cost responsibility«. could ultimately llt• 

reassigned to PSEG.' In a final irony, a few years earlier PSEG had been 

5, Preventing unintended consequences 

How to prevent the 

with FERC, First, PERC 

Island 

lJ New York !'ower Authority, 'Motion To Intervene And Supportive Comments Of The 

tll1ng 

glomll transmission lines. The narrowest version of "beneficiary pays" 

too restrictive, because ir tends to rely too heavily on a staIn conventional electric power 

mode! will slww that a transmis· 

frastructurt: policy, and make electric America great again. 

of 

tide 1Nritten Clarke Bnmo prepared 

!ion in June 2013. The author was a principal that 

developed the Neptune and Hudson projects, whirh arc discussed in this 
45 

Mr. OLSON. Thank you, Mr. Krapels. 

Our next witness is Jennifer Curran. Jennifer is the vice president, system planning, at Midcontinent ISO. But most importantly, 

she is a graduate of Rice University, my alma mater. 

Ms. CURRAN. Go, Owls. 

Mr. OLSON. Go, Owls. 

Five minutes, ma’am. 

STATEMENT OF JENNIFER CURRAN 

Ms. CURRAN. Good morning, Vice Chairman Olson, Ranking 

Member Rush, and members of the subcommittee. 

As noted, I am Jennifer Curran, Vice President of System Planning for the Midcontinent Independent System Operator, or MISO, 

as we are more commonly known. 

I appreciate the opportunity to be here with you today as you examine the state of the Nation’s electric transmission system, and 

I hope the insight into how MISO plans transmission are useful to 

you as you work to shape U.S. energy policy. 

MISO is a 501(C)(4) not-for-profit social welfare organization 

with responsibility for ensuring the reliability of the high-voltage 

electric transmission system to deliver low-cost power to customers. 

That mission is reflected in our approach to transmission planning. 

We seek not to minimize the cost of transmission, but rather to 

identify transmission, which maximizes value to customers in the 

form of overall lower total energy costs. 

The system that MISO manages is geographically the largest in 

North America. It spans from Manitoba in Canada down through 

all or parts of 15 States to the Gulf of Mexico. As you might imagine, a geography that wide presents a lot of diversity in resource 

types, weather, State policies, and consumer preferences as it relates to electric supply. Transmission is a key tool to optimize that 

diversity for the benefits of customers. That diversity also presents 

challenges as we seek to design transmission plans and, probably 

most importantly, determine who will pay for them. Even prior to 

Order 1000, MISO was planning not just for reliability, but also for 

economics and public policy. 

Of the $30 billion of transmission investment that has been enabled through the MISO planning process, approximately 20 percent of that is associated with a long-term regional planning effort 

to address the changing resource mix, known as the Multi-Value 

Projects. 

The Multi-Value Project portfolio is a set of 17 projects that are 

distributed widely across the north and central regions of MISO. 

They provide benefits of two to three times the cost, predominantly 

in the form of access to existing and new low-cost energy resources, 

and reliably enable the renewable portfolio standards in the Midwest. 

Transmission like the Multi-Value Projects is a longer-term view. 

We are about halfway through the implementation of the MultiValue Projects, with the final project scheduled to go into service 

in 2023. In the meantime, as has been noted, we continue to see 

a great deal of change in the electric industry. So where do we go 

from here? 

46 

I think the challenge in front of us is probably best described by 

the two questions I get most frequently about transmission planning: MISO, why have you not developed the next set of regional 

and even interregional transmission? And, MISO, why are you 

thinking about additional transmission that we clearly won’t need? 

So that dichotomy is clearly representative of the diversity that 

I mentioned, and that diversity becomes even broader as we expand beyond the regional boundaries and plan with our neighbors. 

But it is also reflective of the uncertainty of the future as it relates 

to electricity. 

The MISO planning process uses a scenario-based approach. We 

try to bound the potential outcomes of the future and then look for 

transmission projects that will be valuable in all of those futures. 

If we can find transmission that is valuable across that wide 

range of objectives, then we can feel comfortable that the benefits 

will continue to accrue to customers and that we can continue to 

recommend that transmission. We often refer to these as no-regrets 

projects. 

We have a lot of planning to do to determine whether there is 

a future set of transmission that has benefits in excess of costs and, 

probably most critically, to come to consensus on who will pay for 

that transmission, who sees the benefits and believes that the cost 

they will bear will be in line with those benefits. 

Nonetheless, I believe that regional and interregional transmission will be a critical part of the overall solution set as we seek 

to ensure the reliability, the efficiency, and the resilience of the 

electric grid into the future. 

Thank you. 

[The prepared statement of Ms. Curran follows:] 

47 


30978.034

Testimony of Jennifer Curran 

Vice President, System Planning 

Midcontinent Independent System Operator, Inc. (MISO) 

Before the House Committee on Energy and Commerce 

Subcommittee on Energy 

"Examining the State of Electric Transmission Infrastructure: 

Investment, Planning, Construction and Alternatives" 

May 10,2018 
48 


30978.035

Executive Summary 

1 

• Midcontinent Independent System Operator, Inc. (MISO) Overview: MISO is a 

501(c)(4) not-for-profit social welfare organization established to ensure the reliability 

of the high-voltage electric transmission system to deliver low-cost wholesale energy to 

consumers. MISO manages about 66,000 miles of high-voltage transmission lines and 

175,000 megawatts of electricity-generating capacity and serves about 42 million people 

across all or parts of 15 states. This regional platform creates $3 billion in annual 

benefits for members and consumers. 

• MISO's Transmission Planning and Development Process: MISO's grid planning and 

facilitation of infrastructure investment has been a key contributor to the region's ability 

to efficiently and reliably manage the ongoing generation portfolio evolution. Our valuebased planning process combines planning to address localized and reliability-related 

transmission issues including compliance with NERC reliability standards, with 

planning focused on regional and sub-regional solutions to economic and/or public 

policy issues. Localized planning focuses on the I 0 year horizon while the regional 

planning aspect may look out 20 years or more. The process provides for a review of 

alternative solutions to identified issues, including non-transmission alternatives to 

projects identified to address reliability concerns. 

Our innovative process was designed to ensure ongoing reliability while facilitating 

what are sometimes long lead time investments in an environment of policy uncertainty. 

The long-term aspect of the process uses a scenario based approach to mitigate that 

uncertainty. We look for projects that will provide value across a range of potential 

future states. These "no regrets" investments will be prudent no matter the actual future. 

Nearly $30 billion of transmission development has been identified in our planning 

process, with approximately $6 billion of that stemming from a long-term, regional 

portfolio of projects recommended in 2011. 

• Challenges and Opportunities: Transmission investments in the MISO region have 

contributed significantly to a resilient MISO grid. As the generation portfolio continues 

to evolve to one of more intermittent and distributed generation, additional regional 

transmission will likely be needed to ensure system reliability and the most economic 

delivery of power. In a region spanning 15 states, diverse viewpoints make consensus on 

transmission needs, and how the costs should be allocated, challenging. That consensus 

becomes even more elusive as we seek to identify transmission needs inter-regionally. 

Overcoming those hurdles in a timely manner is imperative to ensure the grid of the 

future is in place to support the generation fleet of the future. 
49 


30978.036

MISO Overview 

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

the Subcommittee. I am Jennifer Curran, vice president of system planning at the Midcontinent 

Independent System Operator, Inc., or MISO. It is a pleasure to be with you today as you 

examine the state of our nation's electric transmission system. I ho1?e the insights into how MISO 

facilitates transmission investments will be useful to your work of shaping U.S. energy policy. 

I know this committee is interested in hearing about tjle facilitation of transmission system 

investments, including challenges associated with the planning and construction of new 

transmission lines, the effect of existing federal laws and regulations, and the consideration of 

non-transmission alternatives. Before I share MISO's insights on these matters, I would like to 

provide a little background about our organization. 

The Federal Energy Regulatory Commission's (FERC) Order 2000, issued in 1999, established 

Regional Transmission Organizations (RTOs) to be independent entities that plan and operate the 

electric grid on a regional basis to maintain reliability and maximize efficiency. MISO was the 

first ISO to be recognized as an RTO, receiving FERC approval in 2001. 

MISO is a 50l(c)(4) not-for-profit social welfare organization with responsibility for ensuring 

the reliability of the high-voltage electric transmission system to deliver low-cost energy to 

consumers. The system that MISO manages is the largest in North America in terms of 

geographical scope, serving about 42 million people across all or parts of 15 states, stretching 

from the Canadian border to the Gulf of Mexico. Our energy markets are also among the largest 

in the world, with more than $25 billion in annual gross market charges. MISO also serves as the 

2 
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reliability coordinator for MISO entities in these 15 states and the Canadian province of 

Manitoba. A map of the MISO footprint is provided in the Appendix of this testimony. 

Currently, the MISO region contains about 66,000 miles of high-voltage transmission assets with 

an aggregate value of approximately $38 billion, as well as 175,000 megawatts of electricitygenerating capacity. MISO does not own any of these assets. Instead, with the consent of our 

asset-owning members and in accordance with our FERC-regulated tariff, MISO exercises 

functional control over the region's transmission and generation resources with the aim of 

managing them in the most reliable and cost-effective manner possible. The MISO Region is 

predominantly comprised of traditionally structured and state regulated utilities. MISO has a 

robust stakeholder process that allows asset owners, state regulators and all other stakeholders to 

provide input and guidance to MISO on a regular and ongoing basis. 

MISO's mission is to work collaboratively and transparently with stakeholders to enable reliable 

delivery oflow-cost wholesale energy to the end use customers in our footprint. We achieve this 

through innovative wholesale market operations and transmission grid planning. Through 

execution of those functions and a focus on affordable energy we generate substantial benefits 

for the end-use consumers served by our member utilities. MISO performs an annual study, 

called the Value Proposition, to measure and quantify these benefits. In 2017 benefits totaled 

more than $3 billion. Over the last decade, the cumulative value created is about $21 billion. 

A portion of these benefits results from improved reliability and the optimization of all of the 

region's resources. However, the transmission system enables the majority ofthis value- over 

$2 billion annually - by allowing the region to haroess the substantial diversity benefits provided 

by our expansive footprint. MISO's region spans areas that can experience significantly different 

weather at any given time. Demand in those areas peaks at different times. This allows for a 

3 
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more efficient set of supply resources to be employed across those peaks than would be possible 

if demand peaked in all areas coincidently. The transmission grid provides the connections that 

allow low-cost energy to be transferred across the region and the deferral or avoidance of 

additional assets built by individual utilities. Our robust transmission system also provides the 

flexibility and adaptability needed to respond to the profound transformation taking place in the 

electricity industry. 

Evolving our Collaborative Planning Process to Accommodate Changing Generation Mix 

We are experiencing significant changes in the resource mix due to a combination of regulatory, 

political and economic factors. The abundance of low-cost natural gas, combined with legacy 

environmental regulations targeting emissions from coal-fired power plants and state policies 

promoting renewables, has put additional pressure on the traditional generation fleet. 

Additionally, energy-efficiency initiatives and "demand-side" programs that compensate 

customers for reducing their electricity use are growing in popularity, as are emerging 

technologies such as energy storage and distributed-energy systems like rooftop-mounted solar 

panels that allow homeowners to generate their own energy and sell, or receive credits for, 

excess power delivered back to the grid. 

In the MISO region, which has historically been heavily reliant on coal-fired electricity 

generation, the impacts have been notable. For example, while coal-fired generation supplied 

75% of the region's electricity production as recently as 2011, that figure has fallen to less than 

50% today. Conversely, while gas supplied just 6% of the region's energy in 2011, it supplies 

4 
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30978.039

about 27% today. And wind, which was essentially at 0% in 2005 and increased to 4% by 2011, 

is now at 8% and growing rapidly. 

Our regional grid planning and facilitation of infrastructure investments have been key 

contributors to the region's ability to effectively manage this resource portfolio evolution. The 

transition in the generation fleet over the last decade-plus has required that we advance our 

transmission planning process to ensure the grid enables and supports efficient delivery of power 

from the changing generation fleet while remaining reliable and resilient. 

In the initial days of MISO planning, the focus was narrowly on reliability planning- "keeping 

the lights on"- with an emphasis on lowest initial transmission costs as the key driver of 

customer value; an approach largely consistent with utility planning in the traditional, prewholesale market era. However, MISO, in collaboration with our stakeholders, soon began to 

enhance our planning process to account for project benefits beyond just reliability, including 

market efficiency improvements and addressing public policy requirements and objectives. The 

resulting value-based process is designed to maximize value for consumers by identifying 

transmission which minimizes the combined costs of transmission, generation and the energy on 

the system, or in other words lowers the total delivered cost to consumers. Each cycle of the 

process is the culmination of a minimum of 18 months of collaboration between MISO planning 

staff and stakeholders and is documented in the annual publication of the MISO Transmission 

Expansion Plan (MTEP). In total, MISO has facilitated nearly $30 billion in total transmission 

investment since the first MISO Transmission Expansion Plan in 2003. 

The process combines local and regional planning, bringing together needs and projects 

identified by local utilities with projects identified by MISO through our regional view of the 

system. Also factored in are policy and economic driven needs as well as expected generator 

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retirements and additions. Our process also covers the spectrum of near-term through long-term 

assessments of grid needs. A long term view is essential to ensure that transmission, which can 

have long lead times compared to some new generation options, does not become the barrier to 

flexible cost effective supply options that drive the largest part of customer electric bills. 

Reliability planning generally has a near- to mid-term focus, looking at system needs in the 1 to 

10 year horizon. These projects are justified by their role in complying with North American 

Electric Reliability Corporation reliability standards and are usually implemented in 2 to 5 years. 

The process of developing transmission projects includes, when appropriate, evaluation of 

alternative transmission projects to address issues. This includes evaluating non-transmission 

alternatives to ensure the best option is found. Market efficiency planning assesses expected 

system congestion over the 5 to 15 year horizon and develops transmission plans that reduce or 

eliminate congestion to enable customer access to lower-cost electricity through the market, 

recommending transmission projects only when the market efficiency benefits outweigh project 

costs. The handful of market efficiency projects recommended to date have varied in scale and 

scope and in some cases span multiple utility territories. 

The long-term portion of the process looks out 15 to 20 years and is designed to periodically 

assess whether industry trends, such as those driven by changing economics and public policy 

objectives, are creating the opportunity or need for large-scale, regional transmission plans, and 

to inform nearer-term investment decisions. A scenario-based approach is employed, using a 

range of potential outcomes to "bookend" the uncertainty associated with various factors that can 

influence future system needs and thus transmission system design. Variables that are assessed 

across those different potential outcomes, or futures, include: fuel prices; electricity demand 

growth forecasts; generation retirements; state and federal policy impacts; and capital costs of 

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new generation. Futures are created or refreshed on an annual basis to provide a range of views 

on where the generation mix may evolve. Transmission is planned against these future scenarios, 

benefits are quantified, and projects whose benefits exceed costs by predetermined thresholds 

across the scenarios are considered no-regrets investments as they hold up economically against 

various potential future states, mitigating policy uncertainty. 

The process concludes with cost allocation determined by assessment of beneficiaries consistent 

with the project driver or purpose. Where costs are shared between multiple parties, amounts are 

based on how much each entity benefits from the project. Ultimately, this question of who pays 

is the most challenging aspect of the regional planning process. Recommending any large 

transmission project requires a robust business case and a fairly high level of alignment among 

stakeholders; specifically, MISO stakeholders must be aligned in the belief that the project will 

provide the expected benefits, and that the expected distribution of the costs will fairly match the 

expected distribution of the benefits. 

As states in the Midwest were passing Renewable Portfolio Standard mandates and goals, we 

recognized the growing need for transmission to more economically and reliably deliver the new 

resource mix that was occurring due to the policy changes. However, a lack of clarity regarding 

future policy direction and decisions made investing in long-lead transmission lines risky. The 

planning process described above, in conjunction with Midwest governor and state regulator 

leadership on assessing transmission need, and determining how to share the costs, provided a 

path to facilitate needed grid investments in spite of that uncertainty. The approach sought to 

provide regional backbone transmission in advance of a specific resource need ("build it and they 

will come") to ensure greater efficiency in transmission build by thinking about the transmission 

need holistically. This approach also provided hope that transmission, which has a longer lead 

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time than generation, could be available to meet generator needs. As a result, in 2011 a portfolio 

of transmission projects known as Multi-Value Projects (MVP) was approved by the MISO 

Board of Directors. The approximately $6 billion dollar MVP portfolio, is made up of 17 

projects, with most states in MISO's North and Central Regions being home to at least one. 

These projects provide reliability, congestion reduction and public policy benefits that are from 2 

to 3 times greater than costs across the MISO footprint, and the costs are shared pro rata across 

MISO. In addition, at the time of approval it was estimated that they were expected to create 

about 28,000 direct construction jobs and around 50,000 total jobs. 

Planning for Continuing Fleet Evolution 

Continued execution of this process will be needed going forward, as the generation fleet 

continues to evolve. Earlier, I mentioned several factors that have been driving portfolio 

evolution. There is one more; end-use customer preference. Consumers no longer just want 

reliable, low-cost power- they also want it to be green and many want more control and 

ownership over powering their homes and businesses. Many utilities in MISO are developing 

long term resource plans which include increased levels of renewable energy, including in some 

cases distributed energy resources in the form of rooftop solar. New technologies impacting 

energy usage are emerging and expected to become competitive or have increased levels of 

adoption, including energy storage, digital devices such as smart thermostats and electric cars. 

The amount and type of resources requesting to interconnect to our system suggest the changes 

in front of us. MISO currently has over 90,000 MW of requests in our generator interconnection 

queue, an 80% increase just this year. To get a sense of scale, consider that the total installed 

generation capacity in MISO today is 175,000 MW. Utility-scale wind and solar resources 

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represent over 85% of the current MW seeking to connect. While many of the projects in the 

queue will not be built, even a portion will continue to drive changes in the operating profile of 

the MISO fleet. 

The continued growth of utility scale wind and solar as well as distributed generating sources 

will drive the need for more transmission as electricity generating unit scale decreases and 

intermittency grows. The ability not only to meet peak demands, but to move bulk power from 

resource areas to load centers across the footprint in all hours of the day will be needed to 

improve reliability and efficiency of this new resource fleet. Regional transmission will play an 

essential role in optimizing the natural and geographic diversity of these resources. 

Large regional investment tends to be cyclical. In the case of the MVP portfolio, the projects 

were designed to address the amount of renewable energy required by the Renewable Portfolio 

Standards that were in place in 2011. The transmission itself was planned for construction over 

many years; the final lines are expected to be complete by 2023. Given these types oftimelines, 

it is prudent to evaluate the next set of regional investments required to ensure reliable, resilient 

and efficient energy delivery. 

While design and approval of the Multi-Value Project portfolio took time and compromise, 

ultimately stakeholders across the region were able to find common ground on the need for the 

projects, the benefits they would bring, and the need to share the cost. Since the MVPs were 

developed, a number of things have changed that increase the complexity of the task in front of 

us. The 15 states and dozens of utilities serving the over 42 million people that make up MISO 

have a much wider range of resource options available to address their respective policy and 

economic drivers. The sheer size of the footprint has us revisiting the question of how widely 

benefits spread, and thus costs should be shared. In most places the amount of electricity needed 

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at peak times is not growing, and the increase of distributed energy resources makes forecasting 

what type of electricity needs to plan for much more challenging. The different aggregate 

operating profile of the new resource mix suggests that, in order to safeguard resilience, there is a 

need for new benefit measures related to flexibility for the transmission business case. Although 

MISO's administration of the competitive bidding process has been successful, the introduction 

of competitive bidding for transmission through FERC Order I 000 created new business 

interests and created different paradigms for projects with cost allocation versus those without. 

An increased focus on interregional transmission planning has further expanded the set of 

interests we seek to align, and highlighted some fundamental differences in viewpoint around 

how to most efficiently operate the transmission system to maximize the value of the existing 

assets. 

For reasons such as these, along with a broad sense of uncertainty for the future, finding 

consensus among so many diverse viewpoints on system needs, and who should pay for those 

system changes, is a significant challenge in planning for additional large scale transmission 

investment in the MISO region. Nonetheless, we continue to study different aspects of the future 

fleet to assess the potential issues and clarify transmission needs. Ultimately, we remain focused 

on transmission that provides value to users of electricity in excess of the costs that new 

transmission would bring. Timely understanding of what transmission will provide value, no 

matter what the future holds, is imperative to ensure the grid of the future is in place to support 

the generation fleet of the future. 

MISO, as an RTO, has a unique role in the industry and brings a unique perspective to the 

challenges we face. We are policy neutral- we don't advocate for any particular policy. MISO 

instead works to inform policy makers about the impact of planned approaches. We then work 

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with the states, utilities and all other stakeholders in our regions to ensure any policy is 

implemented reliably and efficiently. MISO has utilized this role to create $21 billion in benefits 

for our region while positioning our members to effectively navigate the continuing evolution of 

the industry. We are committed to continued facilitation of grid investment through innovative 

planning and development to optimize the changing resource portfolio and we appreciate the 

opportunity to help inform the discussions that will shape the path forward. 

11 
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30978.046

APPENDIX 

MISO Footprint 

12 
60 

Mr. OLSON. And thank you, Ms. Curran. We will talk about Beer 

Bike and Baker 13 offline. 

Our next witness is Dr. Ralph Izzo. He is the CEO of the Public 

Service Enterprise Group. 

Dr. Izzo, you have 5 minutes. 

STATEMENT OF RALPH IZZO 

Mr. IZZO. Good morning, Mr. Chairman, Ranking Member Rush, 

members of the subcommittee, as well as full committee Ranking 

Member Pallone, who has had a long and exemplary career serving 

the people of my home State, New Jersey. 

I am pleased to provide my point of view on the importance of 

continuing to strengthen and modernize electric infrastructure. 

Today I will highlight one Federal policy that stands as an impediment to that goal and should be repealed, that being FERC Order 

1000. 

I am here representing the Public Service Enterprise Group and 

our subsidiary, PSE&G, a 114-year-old company that is New Jersey’s largest electric and gas utility. PSE&G owns around 1,600 circuit miles of transmission operated by PJM Interconnection. 

Despite the fact that PSE&G has been named the mid-Atlantic’s 

most reliable electric utility for 16 years in a row, much of our electric infrastructure is old. While it has helped power the industrial 

Northeast for nearly a century, in recent years we have had to 

work to replace, upgrade, modernize, and sometimes move parts of 

the grid in order to ensure our system can withstand extreme 

weather events and other threats, for even as our customers are 

using less electricity, their reliance on it has never been greater. 

Of course, we don’t have a blank check. Our investments must 

be prudent. Over the past 10 years we have made improvements 

that have reduced unplanned transmission outages by over 80 percent. So the customer benefit is clear. 

Transmission investment has been helped by Federal policies 

that have recognized the importance of transmission and the risk 

in building large projects. However, Order 1000 stands out as a 

policy that undermines these efforts. 

Enacted by FERC in 2011, Order 1000 was touted as landmark 

reform that would promote efficient and cost-efficient transmission 

planning and remove barriers to development. But in the 7 years 

that we have been living under Order 1000, the promised efficiency 

looks more like confusion, controversy, and chaos. 

Regional grid operators have begun to voice their views. PJM 

CEO Andy Ott last year called Order 1000, and I quote, ‘‘a solution 

in search of a problem that is creating more of a challenge.’’ Southwest Power Pool CEO Nick Brown said it created, ‘‘more overhead 

and more uncertainty.’’ 

Our main experience with Order 1000 has been through a competitive solicitation launched by PJM in 2013 for a project to solve 

voltage issues in southern New Jersey. To call the process a mess 

would be generous. PJM made an initial decision and then reversed 

itself. Disputes cropped up between States and stakeholders that 

the RTO had to mediate. 

PJM found itself having to make judgments outside its expertise, 

for example, on which alternatives might secure environmental 

61 

permits or how to interpret the fine print and exclusions when a 

developer says it will cap construction costs. 

Five years into the planning process, we still do not have a constructed project to address a major need on this part of this grid. 

And across the country, other red flags continue to appear. No region outside organized markets have even attempted to administer 

an Order 1000 bid. The Southwest Power Pool spent $5 million on 

a competitive process for an $8 million project that was deemed 

unneeded and never built. The California ISO awarded a project to 

a partnership between a foreign developer and another entity, only 

to see the developer go bankrupt. 

Mr. Chairman, after 7 years these can no longer be called growing pains. But even beyond the chaotic implementation of Order 

1000, there lurks a more fundamental concern. Order 1000 tends 

to drive short-term, Band-Aid fixes for the grid. Projects that solve 

multiple problems and provide long-term value tend not to move 

forward because they are ruled out as being too costly. 

Competition is a positive force. But the goals must be set to 

achieve the outcomes we want. People and businesses depend on an 

efficient electric system that is resilient for the long-term against 

an array of very real threats. Leaving Order 1000 in place risks our 

ability to achieve that end. 

Thank you. 

[The prepared statement of Mr. Izzo follows:] 

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Ralph lzzo, Chairman of the Board, President and Chief Executive Officer 

Public Service Enterprise Group 

Subcommittee on Energy 

Energy and Commerce Committee 

U.S. House of Representatives 

May10,2018 

Introduction and PSEG Overview 

Good morning Chairman Upton, Ranking Member Rush, Ranking Member Pallone of the full 

Committee and my home state of New Jersey, and members of the Subcommittee. My name is 

Ralph lzzo and I am the Chairman, President and Chief Executive Officer of Public Service 

Enterprise Group, a diversified public utility holding company headquartered in Newark, New 

Jersey that owns generation, electric and gas transmission and distribution facilities. 

Our utility PSE&G is a 114-year old company and is the largest electric and gas distribution and 

transmission utility in the State of New Jersey. We serve 2.2 million electric customers. We own 

approximately 1567 circuit miles of transmission that is operated by PJM Interconnection, llC 

(PJM), the independent grid operator in a region that spans 13 states and the District of 

Columbia. PSE&G has received the prestigious ReliabilityOne Award as the most reliable electric 

utility in the Mid-Atlantic region for 16 years in a row. 

Thank you for the opportunity to speak this morning on the future of the transmission grid, and 

what it will take to ensure we have the policies in place to continue to drive the right 

investments to serve our customers. I want to first outline the value proposition to customers 

of our efforts to modernize and strengthen the transmission grid. Then I'd like to focus on 

existing federal policy. While many steps have been taken to encourage transmission 

investment in recent years, FERC's Order 1000 stands out as a measure that has hindered 

efficient transmission planning and should be repealed. 

PSE&G Grid Investments and Value Proposition 

PSE&G's first concern in the area of transmission is, and has always been, the long-term 

reliability of the grid. We are a franchised public utility with an obligation to serve under state 

law. If the lights go out in New Jersey, we are the ones that customers call, and we are the ones 

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elected leaders call. At the same time, PSE&G is always seeking to make cost-effective 

investments. We know we do not have a blank check- we must answer to our regulators and 

customers. Our investments must be prudent. 

let me give you a sense of the Investments PSE&G has been making in our system, and what the 

value of these investments has been to our customers. PSE&G has been actively involved in 

upgrading and adding to its transmission system over the last several years. For instance, we 

are in the process of converting our aging 26 kV system to a more robust 69 kV system. Our 26 

kV system was built in the 1920s and was fine for its time but is not adequately suited to 

address long-term customer needs. For our new 69 kV facilities, we are using modernized 

equipment and stronger poles with a higher capacity for moving power throughout our system. 

Our investments have also included large and challenging Extra High Voltage (EHV) transmission 

projects covering hundreds of miles in some of the most densely populated areas in the nation. 

This includes the Susquehanna-Roseland project completed several years ago by PSE&G and 

PPl, which replaced 90 year-old towers along the transmission backbone that powered the 

industrial northeast corridor nearly a century ago. We have also constructed many smaller 

projects on city streets and in tight areas that put us in close proximity to residents, including 

replacing 1920s vintage poles and stations before a reliability threat presents itself. And finally, 

Superstorm Sandy In 2012 devastated New Jersey and presented extraordinary challenges to the 

transmission and distribution systems In our area, prompting us to replace, harden, smarten, 

and even move electric infrastructure to improve the resilience of the system against the 

extreme weather events that are becoming all too common. 

Collectively, these projects have achieved multiple objectives - addressing reliability concerns, 

improving resiliency, reducing congestion and increasing access to lower cost generation 

resources. 

But just what is the value proposition to customers of these investments? The transmission 

infrastructure that moves vast amounts of electricity is essential to economic well-being and 

quality of life. As President George W. Bush said around the time the Energy Policy Act was 

signed into law, "We have modern interstate grids for our phone lines and our highways. It's 

time for America to build a modern electricity grid." Transmission remains absolutely critical 

from both an economic standpoint and from a reliability and security standpoint. 

When the power is out, the results are economically devastating. In 2017 alone there were 

sixteen (16) costly weather and climate events in the United States and Puerto Rico, including 

Hurricanes Harvey, Irma and Maria. And these 16 events cost over $300 billion. While we 

cannot control the weather, we can proactively continue to make investments that will better 

prepare our customers for these events by both preventing outages and minimizing their 

duration. Superstorm Sandy cost New Jersey customers 775 million hours of lost electricity 

service. Yet, due to our investments in our transmission system, during the period between 

2 
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2013 and 2017, the number of unplanned outages on the transmission system (138kv and 

above) declined from 111 to 44. Thus, our investments have paid dividends for our customers. 

U.S. 2017 Billion~Oollar Weather and Climate Disasters 

https://www.climate.gov/news-features/blogs/beyond-data/2017-us-billion-dollar-weather-and-climatedisasters-historic-year 

Given that we are seeing more and more extreme weather, continued resilience investments 

are vital. As FERC Commissioner Richard Glick recently noted, "the record demonstrates that, if 

a threat to grid resilience exists, the threat lies mostly with the transmission and distribution 

systems, where virtually all significant disruptions occur. It is, after all, those systems that have 

faced the most significant challenges during extreme weather events." Although I am sure 

Commissioner Glick was not suggesting we should ignore generation resiliency, he rightly 

identifies that transmission resilience investments are needed to ensure that the lights remain 

on, that trains and planes can run, that businesses can operate and that people can go to work. 

3 
65 


30978.050

400 

1911~17 Y'""<·to.Dala llni!e<i $!ale~> S!!llon.OOIIar Dlusltilr 1\lven! C""t (C:I'i· 

A<lju•>t.,<ll 

-2005 

2011 

-Awrag.a 

https://www.climate.gov/news-features/blogs/beyond-data/2017-us-billion-dollar-weather-and-climatedisasters-hlstoric-year 

There is no better testament to the criticality of our grid than the fact that bad actors are 

increasingly trying to take it down. As FERC Commissioner Cheryl LaFleur testified before this 

Subcommittee a month ago, "Hacks on the grid are constant. Every year, electric grid attacks are 

either a slight majority or slightly below 50 percent" of aU cyber attacks in the United States. 

PSE&G is working closely with PJM and with other transmission owners in the region to ensure 

that the grid remains secure from physical and cyber security threats. This will not be an easy or 

static fix, and will require ongoing investment to build redundancy into the system. 

Any period of major infrastructure development and replacement raises questions about the 

cost of these investments; these questions are appropriate, and are an important part of 

balancing resiliency and cost. And yet, as the data above suggests, not investing in our critical 

infrastructure will cost customers far more in many cases than making the initial investments in 

upgrades. In addition, notwithstanding my company's investment In needed transmission over 

the past several years, the typical PSE&G residential customer electric bill has actually declined 

7% from its 2010 level due to lower prices for electric supply. This makes for an opportune time 

to make needed investments. 

In our region, transmission investments have the corollary benefit of reducing congestion on the 

grid, which in turn further lowers costs for customers. In PJM's Independent Market Monitor's 

(IMM} 2017 State of the Market Report, the IMM noted that, while in 2008, congestion costs 

totaled 6.0% of PJM billing, in 2017, the percentage had declined to 1.7%. 

4 
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30978.051

Federal Policy 

Mr. Chairman, there is no question that transmission investment over the past decade or more 

has been supported by many federal policies that explicitly recognize the importance of 

transmission, as well as the inherent risk to investors of large transmission projects. By contrast, 

other more recent policies such as FERC's Order 1000 have introduced complexity and confusion 

in the transmission planning process, and should be re-examined before its worst consequences 

begin to manifest themselves to consumers. 

By way of history, we all remember the Northeast Blackout in August 2003. This event knocked 

out power across the Eastern United States and parts of Canada, affecting approximately 50 

million people and resulting in 592 million hours of lost electricity service. Shortly after the 

Blackout, Congress enacted the Energy Policy Act, articulating a statutory directive to bolster 

investment in the Nation's transmission infrastructure, reduce congestion and lower overall cost 

to consumers. Congress designated the North American Electric Reliability Corporation {NERC) 

as an Electric Reliability Organization, with the authority to issue mandatory reliability standards 

and impose them on the industry. Implementing the Energy Policy Act, FERC then issued an 

Order establishing important transmission rate incentives that would be available to 

transmission owners to stimulate investment. 

In 2011, a federal Rapid Response Team for Transmission {RRTT) was formed, made up of nine 

agencies, to accelerate transmission development by streamlining the federal permitting 

process. The RRTT found that seven projects, including the PSE&G/PPl Susquehanna-Roseland 

project, were of national priority. Finally, in 2016, the DOE released a Final Rule to streamline 

and expedite transmission projects, viewing this action as an important step to spur continued 

transmission development. 

All of these steps have been important, and efforts in these areas should continue. But I'd like 

to turn my attention to a more recent policy initiative that stands in stark contrast to these 

other helpful measures: that is the misstep known as FERC's Order 1000. Enacted in 2011 by 

FERC under then Chairman Wellinghoff, it was touted as a landmark reform that would 

"promote efficient and cost-effective transmission planning ... "; "remove barriers to 

development of transmission facilities ... " and "promote competition in regional transmission 

planning processes." 

My company opposed Order 1000 when it was initially proposed, because we felt it was a 

misguided effort to carry out climate and environmental policy through planning of the 

transmission grid. While we wholeheartedly support the agenda to move toward cleaner, 

lower-emitting sources of energy, our view was that upending the transmission planning process 

that worked well was not the right answer and would create more problems than it solved. 

5 
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30978.052

Farfrom the promised efficiency, what Order 1000 has sown in transmission planning in the PJM 

region is political discord among states; confusion as to the process among transmission 

planners, potential transmission investors and grid operators; wasted dollars by all involved ---

and predictably, delay. It's no wonder that the vast majority of transmission being built in PJM 

today is occurring outside the Order 1000 process. 

Our most direct experience with transmission planning in the era of Order 1000 has been a 

competitive solicitation process run by the PJM grid operator for a project called Artificial Island, 

a needed transmission upgrade to address voltage issues at PSEG's 3,500 megawatt nuclear site 

in Southern New Jersey. PSE&G has been selected to build a sizeable portion of the line but not 

the entire project. 

PJM opened the bidding on the Artificial Island project in April2013. To call the process chaotic 

would be generous. We have seen the RTO make an initial project selection only to later 

reverse itself. We have watched the RTO attempt to arbitrate disputes between states. At one 

point the RTO had to suspend and reboot the entire solicitation. We have seen the RTO try to 

scrutinize, interpret and validate the fine print and exclusions when a developer says it will 

adhere to a cost cap for construction. We have seen the RTO try to play the role of mediator 

between stakeholders. We have seen the RTO try to pre-judge the feasibility of certain projects 

based on their ability to secure environmental permits. 

Mr. Chairman, very few of these are appropriate roles for a regional grid operator. They don't 

have the resources, and in many of these instances they don't have the expertise, nor should 

they. It should be no surprise that this process is now in year five and has yet to yield a 

constructed transmission solution to solve the reliability problem on this section of the grid. 

Yet if it were just a matter of what Order 1000 is not achieving, it might be tempting to leave it 

intact and just find a work-around, and turn our attention to other problems. 

But it's Important to also look at how Order 1000, if left on the books, would change the very 

nature of transmission investment, not necessarily with the long-term need of customers in 

mind. The fact Is, Order 1000 even at its best would not facilitate the type of robust 

transmission solutions that provide long-term value to customers. A project such as 

Susquehanna-Roseland, which resolved 23 PJM-identified reliability violations, replaced aging 

infrastructure and reduced congestion, would not ever emerge from an Order 1000 competitive 

solicitation because it would be deemed to "cost" too much. Order 1000 drives investment to 

the band-aid, shorter-term solution, not the solution that is most cost-effective for customers in 

the long run. This hardly seems the path to effectively address the risks customers face from an 

aging infrastructure, extreme weather, cyber and physical security threats and the urgent need 

for a diverse and resilient generation supply. 

Some may discount our observations on Order 1000 as sour grapes over a single project 

outcome. But the truth is that since the adoption of Order 1000 the better part of a decade ago, 

6 
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30978.053

several independent grid operators have recognized the need to limit its application, and many 

have started to share their views more publicly. Last year PJM CEO Andy Ott stated that the 

Order is "almost like a solution in search of a problem. It's actually creating more of a challenge 

to investment." 

Mr. Ott's sentiments were echoed by Southwest Power Pool CEO Nick Brown who remarked 

that the Order "created more overhead and more uncertainty at a time when we didn't need 

more overhead in order to invest in transmission." 

In fact, the embrace of Order 1000 across the country has been tepid at best: 

• No planning region in the U.S. that is outside of an organized RTO/ISO market has 

opened up a single competitive transmission bidding opportunity post-Order 1000. 

• One ISO region- the !SO-New England- has not opened a single competitive 

solicitation. 

• The New York ISO began its competitive transmission process in August of 2014. In 

October of 2017 it awarded its first project. Its second project has yet to be awarded, 

almost four years after NYISO began its efforts. 

• The Southwest Power Pool has opened one solicitation, resulting in an $8 million project 

that was ultimately determined not to be needed and the incurrence of approximately 

$5 million in administrative costs to run the bidding process. 

• The Mid-Continent ISO has opened two bidding opportunities. One resulted in the 

award of a $46 million project after a year-long process. The other is ongoing at the 

present time. 

• The California ISO has not opened a competitive solicitation since 2016. Moreover, in 

2015, the California ISO awarded a competitive project to a partnership between a 

foreign developer and another entity, and the developer subsequently went bankrupt. 

Former FERC Commissioner Tony Clark, my fellow panelist, recently stated, "{F]or all its good 

intentions, [Order 1000] is today a rule that has largely fallen short of accomplishing its goals. 

Unfortunately, the failure of it to fulfill its potential has not come without costs. ... [N]ow is a 

good time for the Commission to consider an Order No. 1000 reassessment." 

I'd like to take this sentiment a bit further and suggest that it should just be repealed. Order 

1000 has been on the books for almost 7 years. Its problems can no longer be called growing 

pains. I would suggest that at a minimum and right away, FERC should "hit the pause button" 

on Order 1000 until and unless the planning regions can demonstrate significant benefits 

flowing from the Order. There should be no further Order 1000 activity in the form of open 

solicitations or windows until such a demonstration has been made. 

7 
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Conclusion 

In conclusion, PSE&G wholeheartedly supports the bipartisan goal of investing in this nation's 

infrastructure, including our transmission grid. We are deploying considerable capital today to 

this end, and we stand ready to work with Congress, FERC and many others on policies that will 

ensure we can do so in a way that delivers the most long-term value, and facilitates the most 

resilient and most efficient electric system possible for our customers. We need to take a hard 

look right away at how Order 1000 is impeding these goals. 

Thank you and I look forward to taking your questions. 

8 
70 

Mr. OLSON. Thank you, Dr. Izzo. 

The chair now calls upon John Twitty. As was mentioned by my 

colleague from Missouri, he is Executive Director of the Transmission Access Policy Study Group and a dear friend of Mr. Long. 

So offline, you probably have some stories that about him that 

we would all like to hear. You have 5 minutes. 

STATEMENT OF JOHN TWITTY 

Mr. TWITTY. Chairman, indeed, I do. 

Well, good morning, Mr. Chairman and members of the subcommittee. I am John Twitty, Executive Director of TAPS, the 

Transmission Access Policy Study Group. Our association has been 

active here in the Capitol and at FERC protecting the interests of 

transmission-dependent utilities. We represent municipal utilities, 

joint action agencies, a rural electric cooperative, and an investorowned utility, serving about 1,200 utilities with retail customers in 

35 States. 

As load-serving entities dependent upon the transmission facilities of others, TAPS members recognize the importance of a robust 

grid and have long advocated policies to get needed transmission 

built, but are keenly aware that expansion must be achieved at 

reasonable cost. 

By enacting Section 217(b)(4) of the Federal Power Act of 2005, 

Congress gave FERC clear instructions on transmission planning 

and expansion. FERC is directed to facilitate planning to meet the 

reasonable needs of load-serving entities and enable load-serving 

entities to secure long-term firm physical or equivalent financial 

rights for long-term supply power arrangements made, or planned, 

to meet their service obligations. 

These directives translate into steps FERC can and should take 

regarding transmission planning and investment. But that is not 

happening to the degree necessary to meet Congress’ mandate. 

First, the grid has to meet the needs of load-serving entities. Although FERC has established rules for an open and transparent 

transmission planning process, even FERC has recognized that this 

is not happening consistently. 

We are particularly concerned that transmission-dependent, loadserving entities do not have a seat at the table the way they would 

if they shared ownership in the grid. Joint transmission ownership 

arrangements where all load-serving entities share ownership of 

the grid, which have occurred in many States, have a long history 

of ensuring that the transmission needs of all load-serving entities 

are met consistent with Section 217. They also facilitate the State 

siting process and spread investment risk and responsibility and 

provide an opportunity for small load-serving entities to offset their 

increasing transmission rates against transmission revenues, thus 

reducing cost to ultimate customers. 

Second, we need to be sure our investment in new transmission 

is appropriate, consistent with Section 217’s focus on the reasonable needs of load-serving entities. TAPS members have experienced rapid increase in transmission cost. While a portion of the 

increase is no doubt justified, transmission has become an investment magnet. The potential for guaranteed incentive-elevated returns on equity on low-risk transmission assets may spur investVerDate Nov 24 2008 13:48 Aug 08, 2018 Jkt 037690 PO 00000 Frm 00076 Fmt 6633 Sfmt 6633 I:\MY DOCS\HEARINGS 115\HEARINGS\115-127 CHRIS
71 

ment that is not necessary. While we support FERC’s ground-up 

consideration of grid resilience, it should not become a blanket justification for excessive investment. 

Third, FERC has fallen short in fulfilling Section 217’s directives 

regarding long-term transmission rights, particularly as to the capacity associated with long-term power supply arrangements on 

which load-serving entities rely for resource adequacy. This exposes 

load-serving entities to increased cost, especially if the RTO choices 

of large transmission owners have left them with loads and resources in multiple RTOs. It also makes new investments riskier. 

Fourth, above-cost incentives are not needed to attract investment. There is no shortage of entities seeking to invest in low-risk 

transmission assets at FERC’s base equity return that is intended 

to reflect the cost of attracting capital. There is no need for incentive rates of return, much less to expand their availability beyond 

opportunities provided under current FERC policy. Those seeking 

transmission incentives should not be permitted to turn away loadserving entities in the footprint seeking to make their load ratio investment in the grid. 

Finally, the transmission planning process can also be a more effective vehicle for inclusive transmission investment. Non-incumbent transmission developers, especially those that accommodate 

participation by small load-serving entities, should have a fair opportunity to develop needed new transmission. 

Congress should encourage the Commission to reinvigorate the 

Order 1000 competitive transmission development process in a 

manner that will promote joint transmission ownership, as well as 

to use competitive discipline to curb rising transmission cost. 

At TAPS, we want to be part of the solution so long as the needs 

of our customers are met. And I look forward to this discussion. 

Thank you, Mr. Chairman. 

[The prepared statement of Mr. Twitty follows:] 

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Testimony of John Twitty 

on behalf of 

Transmission Access Policy Study Group (TAPS) 

Before the Committee on Energy and Commerce Subcommittee on Energy 

United States House of Representatives 

Hearing on Examining the State of Electric Transmission: 

Investment, Planning, Development and Alternatives 

May 10, 2018 

Thank you for the invitation to testify regarding the important topic of Examining 

the State of Electric Transmission: Investment, Planning, Development and Alternatives. 

My name is John Twitty, and I am the Executive Director of TAPS-the Transmission 

Access Policy Study Group, an association of transmission dependent utilities in more 

than thirty-five states, promoting open and non-discriminatory transmission access. 1 Our 

membership includes municipal utilities, as well as a cooperative and an investor-owned 

utility. Some TAPS members are in areas served by a regional transmission organization 

("RTO"), and a number of members have loads and diverse resources in multiple RTOs 

due to the RTO-membership decisions of large transmission owners. Other TAPS 

members are located in non-RTO regions. 

As load-serving entities (utilities with a legal or contractual obligation to serve 

customers) dependent on the transmission facilities largely, if not entirely, owned by 

others, TAPS members recognize the importance of a robust transmission grid to 

competitive generation markets, and have long advocated policies to get needed 

transmission built.2 But as transmission customers that must pay transmission rates to 

1 For additional information on TAPS, see https://tapsgroup.org. 

2 See TAPS, Effective Solutions for Getting Needed Transmission Built at Reasonable Cost (2004) ("TAPS 

White Paper") , available at: http://www.tapsgroup.org/wpcontentfuploads/20 !3/0 l/effectivesolutions2.pdf.; TAPS, Inclusive Joint Transmission Ownership 
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serve their load, TAPS members are also keenly aware of the need to ensure that 

necessary transmission expansion is achieved at reasonable cost. Consumers and 

businesses should not be burdened with transmission rates that are elevated by above-cost 

incentives that are not needed to attract investment or that fund unnecessary facilities. 

We appreciate your focus on these issues that are crucial to the ability of loadserving entities to continue to provide the reliable, affordable electric service required for 

our Nation's social and economic vitality. My comments will focus on the direction 

Congress has already provided to the Federal Energy Regulatory Commission ("FERC" 

or "the Commission") through Section 217 of the Federal Power Act ("FP A"), and 

outline other steps that should be taken to better achieve that provision's goal of a robust 

transmission grid at reasonable cost designed to meet the reasonable needs of loadserving entities. 

I. CONGRESS HAS INSTRUCTED FERC THAT GRID PLANNING 

AND EXPANSION SHOULD FOCUS ON THE REASONABLE 

NEEDS OF LOAD-SERVING ENTITIES 

Section 217(b)(4) of the FPA, enacted as part of the Energy Policy Act of2005, 

provides key congressional directives to PERC on transmission planning: 

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 longterm basis for long-term power supply arrangements made, 

or planned, to meet such needs. 

Arrangements: An Effective Means to Getting Needed Transmission Sited and Built (2012) ("TAPS 

Position Paper"), available at: https://tapsgroup.org/wp-content/uploads/2013/0lffAPS-Joint-OwnershipWhite-Paper.pdf. 
74 


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Section 217(b)(4) thus established Congress' clear guideposts to FERC as to transmission 

planning and expansion. FERC is directed to: 

a. Facilitate planning to meet the reasonable needs of load-serving entities to 

satisfy their service obligations; and 

b. Enable load-serving entities to secure long-term firm physical, or equivalent 

financial, rights for long-term power supply arrangements made or planned to 

meet those service obligations. 

As recognized by the D.C. Circuit, "Section 217(b)(4) creates a requirement for the 

Commission .. .''3 

Section 217(b)(4)'s directives translate directly into steps FERC can and should 

take regarding transmission planning and investment to assure that Congress' express 

intent is achieved; but that is not happening to the degree necessary to meet the 

Commission's obligations under the law. I will discuss several of these below. 

A. Load-serving entities should have a seat at the table to ensure 

their reasonable needs are planned for 

Through its Order 890 and Order I 000 rulemaking proceedings, FERC has 

required an open and transparent transmission planning process. In doing so, it has 

expressly recognized that this process is intended to be consistent with 

Section 217(b)(4).4 

The Commission recently recognized the importance of open, inclusive and 

transparent processes to transmission planning when it found the planning process 

undertaken by certain PJM transmission owners to be unjust and unreasonable, and 

3 S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41, 90 (D.C. Cir. 2014) (",not for utilities."). 

4 Order 890-A, P 24 (stating that to "appropriately balance the needs of these various classes of 

transmission customers, including the transmission provider's native load, [load-serving entity] customers 

serving network load, and other firm users of the system ... is entirely consistent with, if not expressly 

required by, FPA section 217"). · 
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inconsistent with the transparency and coordination principles required for a compliant 

planning process.5 As a result of these deficiencies, stakeholders did not have an 

opportunity to have meaningful input into the planning process. Similar concerns about 

the lack of transparency in the transmission planning process have been raised in other 

regions. For example, stakeholders in California have filed a complaint at FERC alleging 

that Pacific Gas and Electric is improperly developing 80 percent of its transmission 

projects without stakeholder input.6 

TAPS supports the Order 890 and 1 000 planning requirements, and urges 

Congress to continue its appropriate role in conducting oversight ofFERC to ensure that 

these requirements are met; more is needed to ensure that Congress' Section 217(b)(4) 

mandates are fully satisfied. Specifically, more should be done to encourage joint 

transmission ownership arrangements. Under such arrangements, load-serving entities 

embedded in the transmission system have the opportunity to invest in their load-ratio 

share of the transmission grid; they have a seat at the "grown up" table in the planning 

process, so they can play an integral role in ensuring their load is being properly served 

with necessary infrastructure. Non-profit," public power load-serving entities also have no 

interest in "gold-plating" the transmission system, so including them in the transmission 

planning process helps to assure that the grid is robust and reliable, without imposing 

unnecessary costs. 

s Monongahela Power Co., 162 FERC 1j 61,129 (2018) ("PJM Order''). 

6 California PUC Complaint Targets PG&E Transmission Planning, PowerMarketsToday (Feb. 7, 2017), 

https://www.powennarketstoday.com/public/Califomia-PUC-complaint-targets-PGE-transmissionplanning.cfin?utm source=Real%20Magnet&utm medium=Email&utm campaign=! 08112161. 
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Such arrangements have a long track record of ensuring all load-serving entity 

needs are fully and fairly considered in the planning process. They also bring together 

diverse interests to expedite state siting and local permitting processes, thereby 

facilitating the construction of needed transmission. As detailed in TAPS' White Paper 

and Position Paper, such arrangements can take the form of an inclusive transmissiononly company (ortranscos), such as the Vermont Electric Power Company, formed in 

1956, and the more recent example of the 200 !-formed American Transmission 

Company in Wisconsin, Michigan, Minnesota, and Illinois? Inclusive shared system 

arrangements are another option with a long history of success in Georgia, Indiana, 

Minnesota, North Dakota, and South Dakota, and have more recently been established in 

Connecticut. Joint ownership arrangements also include inclusive arrangements for new 

facilities, such as CapX2020, a joint transmission-planning process in the northern 

Midwest. CapX consists of eleven investor-owned, municipal, and rural cooperative 

utilities in Minnesota, North Dakota, South Dakota, and Wisconsin that have jointly 

planned needed transmission upgrades and have opportunities to jointly own those 

facilities. CapX investment now amounts to some $2 billion and includes four 345-kV 

transmission lines and a 230-kV line. 

The Commission itself has repeatedly recognized the value of these arrangements. 

For example in Order 1000, the Commission stated:8 

We reiterate here our statement in Order No. 890 that we 

believe there are benefits to joint ownership of transmission 

7 GridLiance's recent efforts to partner with public power and cooperatives in transmission investments 

provide another example of this type of arrangement. 

8 Order 1000, P 776 (citing Order 890, P 593). See also Order 1000-A, P 81 ("[T]he Commission supports 

investment in transmission infrastructure by transmission dependent utilities."). 
77 


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facilities, particularly large backbone facilities, both in 

terms of increasing opportunities for investment in the 

transmission grid, as well as ensuring nondiscriminatory 

access to the transmission grid by transmission custo~ers. 

The Commission commented favorably on the benefits of such arrangements in its 

rulemakings implementing FPA Section 219's authorization of incentive-based rate 

treatrnents.9 The Commission's 2012 Policy Statement on Incentives "encourages 

incentives applicants to participate in joint ownership arrangements and agrees ... such 

arrangements can be beneficial by diversifying financial risk across multiple owners and 

minimizing siting risks."10 The Policy Statement emphasizes risk-reducing (rather than 

rate-increasing) incentives by stating the Commission's expectation that applicants take 

all reasonable steps to mitigate risks before they seek an incentive return on equity, 

noting that "[ e ]vidence regarding whether an applicant for incentives considered joint 

ownership arrangements may be relevant in assessing whether the applicant took 

appropriate steps to minimize its risks during project development." 11 This 

encouragement, however, has not led to tangible, real world progress. 

B. Above-cost rate incentives do not advance the objective of 

planning for a grid right-sized to meet the reasonable needs of 

load-serving entities 

Section 217(b)(4) expressly anchors planning and expansion in meeting the 

reasonable needs of load-serving entities. Congress did not mandate a "build it and they 

9 See, e.g., Order 679, P 354 ("[P]ublic power participation can play an important role in the expansion of 

the transmission system .... Encouraging public power participation in [new transmission projects] is 

consistent with the goals of Section 219 by encouraging a deep pool of participants."). 

10 Promoting Transmission Investment through Pricing Reform, Policy Statement, 141 PERC~ 61,129, P 

24 (2012). 

11 ld ,at n. 33. 
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will come" approach. TAPS advocates for a robust grid that supports competitive 

markets and long-term transmission rights to support long-term power supply 

arrangements to meet service obligations, but is concerned about mounting transmission 

rates. 

TAPS members in a number of regions have experienced rapid increases in the cost 

of transmission service. For example: 

• American Electric Power, a utility serving customers in eleven states with an 

over 40,000-mile transmission network, has increased its zonal transmission 

rate from $27/kW-year to $54/kW-year between 2012 and 2017-meaning 

rate increases of about 15 percent per year. For PPL, another large 

transmission provider in PJM, the zonal transmission rate increase over the 

same period was even larger. It went from $24/kW-year to $61/kW-year, 

growing at about 20 percent per year. 

• In New England, total regional network service transmission rates have 

increased from about $15/kW-year in 2003 to just over $103/kW-year in 

2016, an average annual increase of about 16 percent. 

• In the Southwest Power Pool, which extends from North Dakota to the Texas 

Panhandle, the average annual rate increased from $5.97/kW-year in 2013 to 

$13.14/kW-year in 2018. That means an average annual increase of about 17 

percent. 

While a portion of the increased transmission rates is justified by the need to 

maintain reliable service, TAPS is concerned that transmission has become a magnet for 

excessive investments. The potential for guaranteed, incentive-elevated returns on equity 

on transmission facilities that are low-risk investments, with full cost recovery ensured by 

formula rates, will encourage over-investment. FERC's allowance of forward-looking 

formula rates eliminates any potential for returns to be diminished by regulatory lag. We 

attribute to this low-risk, high-return investment vehicle the increasing trend of 

transmission owners actively seeking to increase their regulated transmission 
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investments, while reducing their exposure to the risk associated with generation 

investments, particularly in deregulated markets. 12 

The FERC-allowed ensured returns on low-risk transmission investments are so 

rich that large transmission owners are reluctant to share the investment opportunity with 

others. In fact, transmission owners have litigated against each other for the lucrative 

opportunity to build. 13 Despite Commission recognition of the benefits of joint 

ownership arrangements, large transmission owners have similarly rejected TAPS 

members' efforts to secure joint transmission ownership opportunities. As a result, small 

load-serving entities cannot offset the increasing transmission rates they must pay others 

against transmission revenues received for their transmission investment. Rather, the 

businesses and consumers that depend on these entities for service bear the full brunt of 

rising transmission rates. 

TAPS is also concerned that the high-equity-return-fueled interest by transmission 

owners and others in investing in low-risk transmission may spur investment that is not 

necessary, or which-particularly given the changes underway in our electric system, 

including flat or declining load growth and the emergence of distributed energy 

resources-could become a stranded cost burdening our economy and our citizens as the 

industry further evolves. We support the Commission's ground-up examination of 

12 Utilities Continue to Increase Spending on Transmission Infrastructure, U.S. Energy Information 

Administration (Feb. 9, 2018), https://www.eia.gov/todayinenergy/detail.oho?jd=34892. 

13 See, e.g., Pioneer Transmission, LLC v. N. Jnd Pub. Servs. Co., 140 FERC 161,057 (2012) (FERC 

denying a complaint brought by Pioneer Transmission arguing that Northern Indiana Public Service Co. 

does not have ownership and investment rights associated with a 765 kV line in Indiana); ITC Midwest, 

LLCv. Am. Transmission Co., LLC, 142 FERC 161,096 (2013), reh'gdenied, 152 FERC 161,155 (2015) 

(FERC granting a complaint brought by ITC Midwest arguing that American Transmission is not entitled to 

ownership and construction of the entirety of the facilities for a 136 mile, 345 kV transmission line). 
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potential grid resilience issues, and we recognize the importance of a robust transmission 

system to resilience. 

However, "resilience" should not b~ permitted to serve as a blanket justification 

for excessive investment. There will always be opportunities to make the grid more 

resilient. The crucial question is what is the appropriate level of resiliency, consistent 

with Section 217(b)(4)'s directive to PERC to facilitate planning for the reasonable needs 

of load-serving entities, allowing them to continue to provide the reliable, affordable 

electric service on which our businesses and consumers depend. 

C. Transmission planning should honor and support long-term 

rights for load-serving entities' long-term power supply 

arrangements 

As Congress recognized in enacting Section 217(b)(4), load-serving entities' 

long-term power supply arrangements are a key contributor to reliability and resource 

adequacy, and should be supported by firm physical or equivalent financial transmission 

rights. Long-term power supply arrangements include not only the moment-by-moment 

deliveries of energy, but also the power or capacity to make the deliveries necessary for 

resource adequacy. PERC's pro forma open access transmission tariff that has been in 

place since its seminal Order 888 rulemaking in the late 1990s defines firm transmission 

service as providing for delivery of capacity and energy. 14 

While PERC has implemented Section 217(b)(4), in part, by enabling loadserving entities in RTOs to secure long-term transmission rights (or equivalent financial 

rights) for the delivery of energy under their power supply arrangements, PERC has 

14 Order 888-A, PERC Stats. & Regs.~ 31,048, at 30,530 (Order 888-A tariff§ 28.3); !d. (Order 888-A 

tariff§ 28.2). 
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refused to apply Section 217's directives to ensure the delivery of the capacity associated 

with these power supply arrangements. 15 As a result, load-serving entities may be unable 

to rely on these long-term power supply arrangements to meet resource adequacy 

requirements, even though their long-term firm transmission arrangements expressly 

provide for the delivery of both capacity and energy. Instead, these load-serving entities 

are effectively forced to purchase, at potentially higher prices, other capacity at their load. 

This disruption ofload-serving entities' reliance on their long-term power supply 

arrangements, including investments in long-lived generation, is a particular problem 

where a load-serving entity's generation is separated from the load to which it has long 

been dedicated by a "seam" created by the RTO choices of the large transmission owners 

in which the load-serving entity's load or generation is embedded. Although the loadserving entity's generation and load may have been in the same RTO when its long-term 

generation commitments were made, the ability of large transmission owners to switch 

RTOs (or join or leave an RTO) without protecting embedded load-serving entities from 

any adverse impacts may later separate the small load-serving entity's generation from 

the load to which it is dedicated. The Commission's acceptance of new RTO resource 

adequacy requirements that fail to fully preserve and honor the load-serving entities' 

long-term rights to firm delivery of its capacity to its load16 undermines these long-term 

1

' Midcontinent Indep. Sys. Operator, Inc., 162 FERC 1!61,176 (2018); PJM Interconnection, L.L.C., 

161 FERC1f61,197,P 178 (2017); PJM Interconnection, L.L.C., 150 FERC 1!61,041, P 19 (2015). 

16 See PJM Interconnection, L.L.C., 161 FERC1f 61,197, PP 175,176, 178 (accepting new deliverability 

assessments that could cause load-serving entities to be deprived of their long-term resources supported by 

long-term firm transmission rights, effectively putting such load-serving entity uses that should have been 

planned for on the margin). 
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- ll -

power supply arrangements and improperly leaves such small load-serving entities (and 

the businesses and consumers which rely on them) exposed to increased costs and risks. 

II. KEYTAKEAWAYS 

A. Congress should reaffirm the importance of FPA 

Section 217(b)(4), and take FERC to task for not fully embracing 

its dictates 

As I've highlighted above, FPA Section 217(b)(4) provides a crucial framework 

for assessing policy choices pertaining to transmission planning and investment. In 

calling for planning for load-serving entities' reasonable needs, including long-term 

transmission rights for long-term power supply arrangements, the statute provides 

essential focus and constraints on the planning process. It points toward an inclusive 

planning process that produces a right-sized grid that meets the needs of load-serving 

entities to provide reliable service, at an affordable cost, to businesses and consumers. 

And it cautions against a planning process that produces grid investment that is not 

necessary to meet those reasonable needs. The Committee should exercise its appropriate 

oversight authority to ensure that FERC takes seriously Section 217' s guideposts as it 

makes policy choices regarding planning and investment in the grid. 

The Committee should also investigate whether Section 217(b)(4)'s second 

directive-that the Commission enable load-serving entities to secure long-term rights 

(physical or financial) for the delivery of their long-term power supply arrangements' 

energy and capacity-has been adequately adhered to. The Commission's failure to 

fulfill its mandate with regard to delivery of capacity, a key component of long-term 

power supply arrangements, undermines the very arrangements Section 217(b)(4) seeks 

to support and honor. 
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B. Equity incentives should be limited 

As I explained, incentive rates of return-that pay investors more than the "base 

return on equity" (i.e., the level required to attract and maintain investors)--place a heavy 

burden on the nation's businesses and consumers with no corresponding benefit. There is 

no shortage of entities seeking to invest in transmission, and thus no need for incentive 

rates of return. These incentive rates of return encourage over-investment in the grid and 

incentivize the exclusion of small load-serving entities from being allowed to make their 

share of needed grid investment, to the detriment of businesses and consumers. 

FPA Section 219(a) authorized the Commission to grant incentive-based rate 

treatments "for the purpose of benefitting consumers." In its 2012 Policy Statement on 

Incentives, the Commission has rightly emphasized risk-reducing incentives, and limited 

the circumstances when it would award equity incentives. Given the significant interest 

in investing in low risk, nearly assured recovery, transmission assets at the Commission's 

"base" equity return that is intended to reflect the cost of attracting capital, there is no 

reason to expand the availability of equity return heighteners beyond those in FERC's 

2012 Policy Statement. 

C. Joint transmission ownership arrangements should be more 

aggressively encouraged 

Although FERC's 2012 Incentive Policy Statement rightly recognizes the role of 

joint ownership arrangements as a way of demonstrating that an applicant for incentives 

is using appropriate mechanisms to minimize risks, it has not yielded expanded 

opportunities for transmission investment by load-serving entities ready, willing, and able 

to make such investments. Given the Commission-recognized benefits of joint ownership 

arrangements (including minimizing state siting and permitting risk, making it more 
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likely that the project will be built), more should be done to make opportunities for all 

load-serving entities in the footprint to invest in their load-ratio share of the transmission 

grid a reality. Doing so would achieve Section 217's purposes by enabling load-serving 

entities to directly participate in ensuring that their reasonable needs are satisfied, and 

would allow them to offset the increasing cost of transmission, benefiting consumers and 

businesses. 

Those seeking transmission rate incentives, particularly incentive equity returns, 

to induce their investment should not be permitted to turn away load-serving entities in 

the footprint seeking to make their load-ratio investment in the grid. Instead, a showing 

that the applicant has offered such investment opportunities on reasonable terms should 

be a prerequisite for incentives. 

In addition, the Order 1 000 transmission planning process can be a more effective 

vehicle for inclusive transmission investments. Non-incumbent transmission developers, 

especially those (like GridLiance) that accommodate participation by small load-serving 

entities, should have a fair opportunity to compete to develop needed new transmission. 

Unfortunately, despite Order lOOO's efforts to promote a competitive transmission 

development process and vigorous competition for those projects that have been open to 

competition, positive results have been limited. FERC Staffs own analysis shows that in 

2016, no proposals submitted by nonincumbent transmission developers were selected by 

any of the transmission planning regions that had competitive proposal windows-a 

strong indication that the Commission's effort to foster more efficient and cost-effective 
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transmission development through competition is significantly flawed. 17 Congress 

should encourage the Commission to revisit and reinvigorate the Order 1000 competitive 

transmission development process in a manner that will promote joint transmission 

ownership, as well as use competitive discipline to curb rising transmission cost. 

Once again, I would like to thank the Committee for this opportunity and look 

forward to your questions. 

17 2017 Transmission Metrics Staff Report at 4, FERC (2017), available at: 

https://www .ferc.gov/legal/staff-reports/20 17 /transmission-investment-metrics.pdf. 

May 10,2018 
86 

Mr. OLSON. Thank you, Mr. Twitty. 

Our final witness is Mr. Rob Gramlich. 

Mr. GRAMLICH. That is right. 

Mr. OLSON. Rob is the President of Grid Strategies LLC. 

You have 5 minutes for an opening statement, sir. 

STATEMENT OF ROB GRAMLICH 

Mr. GRAMLICH. Thank you very much, Vice Chairman Olson, 

Ranking Member Rush, members of the subcommittee. I appreciate 

the opportunity to be here today to talk about the important issue 

of the state of transmission. 

There is no infrastructure more important than transmission, 

which is essential to the reliable and affordable electricity service 

we depend on for almost every modern commercial and individual 

activity. 

Since this subcommittee was involved in passing the Energy Policy Act of 2005, the industry has succeeded in building a lot of 

transmission. Transmission benefits have exceeded the cost by factors of 2 to 3.5 in the major investments in the central region you 

have heard about in MISO and the Southwest Power Pool. 

Transmission investment has enabled over $100 billion of generation investment in rural communities. Transmission investment 

is needed for both a distributed future and a large utility-scale generation future, either one or both. 

We have learned a lot about what works. Regional planning and 

cost allocation in particular have worked well. We should build on 

that success. In my written testimony, I provide nine ideas for expanding transmission and improving its performance. 

However, none of these ideas matter if there is no leadership at 

the Department of Energy or FERC. I think we are waiting for that 

leadership. I fear the agencies are too distracted by misguided proposals to provide life extensions to old power plants. We are all 

wasting our time comparing different dictionary definitions of reliability and resilience when we should be updating policies for 

transmission. If ‘‘resilience’’ is a code word for propping up uneconomic plants, that effort needs to sink on its own poor merits, as 

my former boss, FERC Chairman and Texas PUC Chairman Pat 

Woods, said recently. 

Turning to transmission. To improve transmission, most of my 

recommendations are for FERC, but I have some for DOE and Congress as well. It doesn’t matter if it is under the heading of Order 

1000, 890, 2000, or an entirely new vision they could roll out called 

Order 2020. We need to update transmission policy to create the 

grid we know we will need in the future. 

I recommend that FERC and Congress preserve and build upon 

the twin policies I mentioned of broad regional planning and beneficiary-pays cost allocation. That is what worked in Texas, that is 

what worked in SPP, that is what worked in MISO. That is what 

Dr. Krapels described should be done in the Northeast. 

Number one, FERC should align transmission owner incentives 

for advanced transmission technologies. I didn’t say more incentives. I am not asking for a subsidiary. I said align the incentives 

so that transmission owners have an incentive to deploy cost-effective technologies. 

87 

Number two, FERC should incorporate advanced transmission 

technologies into transmission planning. I don’t like to call it 

nonwires alternatives. I think they are just other transmission options. They should all be considered, along with new lines and 

other assets. 

Number three, FERC should fix interregional planning and cost 

allocation. Clearly, no improvements have been made since Order 

1000’s attempt to improve that. 

Number four, Congress, the Department of Energy, and FERC 

should all improve Federal backstop siting. I think it is important 

for the future grid that we need, and we should make sure it works 

and is used where appropriate. 

Number five, FERC should require proactive planning that captures all of the values of transmission. Too often it gets compartmentalized and not all of the benefits are included. 

Number six, the administration should improve Federal coordination and transmission permitting on Federal lands. 

Number seven, the Department of Energy should harness the authority and capabilities of power marketing administrations. They 

can be involved in transmission, they can utilize Section 1222 of 

the Energy Policy Act of 2005, and help in other ways. 

Number eight, the administration should couple the Department 

of Energy’s planning and support for planning and corridor designation with the Department of Interior’s efforts to identify renewable energy zones and transmission corridors. 

Finally, Congress should consider public financing to right-size 

transmission. Too often we underbuild for the resources that we 

know will be there when our children, their children, and their 

children’s children will benefit from it. 

Those resources are there. We know they will be there even in 

Texas where we built a lot of transmission. We have essentially 

used up that capacity. And looking back, we would have done better to build it the right size. 

I will stop there and look forward to your questions. Thank you. 

[The prepared statement of Mr. Gramlich follows:] 

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Grid 

Strategies ..... 

TESTIMONY OF ROBERT E. GRAMLICH 

PRESIDENT, GRID STRATEGIES LLC 

US HOUSE OF REPRESENTATIVES 

ENERGY AND COMMERCE COMMITTEE 

ENERGY SUBCOMMITTEE 

Hearing entitled "Examining the State of Electric Transmission Infrastructure: 

Investment, Planning, Construction, and Alternatives" 

MaylO, 2018 

Thank you, Chairman Upton, Ranking Member Rush, and Members of the SubCommittee, for inviting me 

to testify on the state of US transmission infrastructure. Since modern society requires affordable, 

clean, and reliable electricity for just about every activity, there is no infrastructure more important than 

the interstate electric network. I serve as Executive Director of the WATT Coalition (Working for 

Advanced Transmission Technologies), on the board of the Americans for a Clean Energy Grid coalition, 

and have a consulting practice called Grid Strategies llC that provides analysis and regulatory policy 

support for clean energy integration and delivery. 

Transmission delivery capability has improved markedly since this Subcommittee helped pass the Energy 

Policy Act of 2005. While providing a source of optimism, that progress still puts the grid nowhere near 

where it needs to be given the age of existing transmission assets, the need to connect new generation 

and consumption sources, the opportunity to develop rural economies by accessing remote resources, 

and the many reliability and economic benefits that would accrue to electricity customers with an 

expanded and more dynamic bulk power network. 

I recommend that FERC and Congress preserve and build upon the major twin policies that succeeded in 

increasing needed transmission investment over the last decade: 

1) broad regional planning, and 

2) beneficiary pays cost allocation. 

I recommend that FERC and Congress remedy the lack of progress in inter-regional transmission and 

innovation through: 

1) Fixing inter-regional planning and cost allocation; 

2) Promoting the adoption of technology and innovations to deliver more over the existing grid; 

3) Implementing limited federal support permitting of inter-state tr.ansmission lines. 
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I. Great progress has been made 

Around the time of the Energy Policy Act of 2005 ("EPAct"), annual transmission investment had fallen 

to around $4 billion per year. Today annual transmission investment is close to five times that amount, 

around $20 billion. This investment has resulted in significant new transmission highways delivering 

very low-cost wind onto the high voltage network. The image below shows new transmission lines in 

black connecting the highest quality wind resource areas (shown in red and purple), particularly in the 

middle of the country with demand centers. 

Figure 1: Recent High-Voltage Transmission and Wind Resources 

A. Benefits to customers of recent transmission investment 

These investments have benefitted customers. The Southwest Power Pool (SPP), the grid operator for 

Kansas, Oklahoma, Nebraska, and parts of neighboring states, evaluated the many categories of benefits 

provided by its recent transmission upgrades.' SPP found that the transmission upgrades it installed 

between 2012 and 2014 create nearly $12 billion in net present value benefits for consumers over the 

next 40 years, or around $800 for each person currently served by SPP, or $2,400 per each metered 

customer. The $16.6 billion in gross savings is higher than SPP's transmission planning models had 

initially estimated, and 3.5 times greater than the cost of the transmission upgrades. As shown in the 

following chart from SPP's report, these upgrades are already paying for themselves, and the benefits 

only grow over time while the costs decline. 

SPP: Benefits {left bar) exceed cost (orange bar) of transmission upgrades 

1200 

1 https://www.spp.org/documents/35297/the%20value%20of%20transmission%20report. pdf 

2 
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SPP's report shows the wide range of benefits provided by transmission: It reduces the cost of producing 

electricity, reduces the need for power plants by improving power system efficiency, increases 

electricity market competition, improves electric reliability, makes the power system more resilient to 

unexpected events, reduces environmental impacts, and creates jobs and economic development. 

The Midwest grid operator, also testifying today, conducted analysis of grid upgrades that are currently 

underway, and found $12 billion to $53 billion in net benefits, or between $250 and $1,000 for each 

person currently served by MIS0.2 The benefits were 2.2 to 3.4 times greater than the cost of 

transmission, an increase from the 1.8 to 3.0 benefit-to-cost ratio that was initially calculated when the 

transmission was planned in 2011.3 MISO found that congestion and fuel cost savings associated with 

providing consumers with access to lower-cost energy sources accounted for between $20 billion and 

$71 billion of the gross benefits, a large share of the total. The New England grid operator similarly saw 

a large reduction in the congestion-related costs paid by consumers after it made significant 

investments in transmission upgrades. Specifically, congestion costs fell from in excess of $600 million 

per year in 2005 and 2006to under $100 million annually.' 

B. Ingredients for Success: planning and cost allocation 

Credit for success in transmission investment in RTO and ISO regions goes to the twin policies of 

transmission planning and cost allocation. Each of these RTO/ISO regions use a form of wide regional 

transmission planning (over wider regions than planning was done prior to ISO and RTO formation), and 

broad beneficiary-pays cost allocation. Texas, as a single state outside of FERC jurisdiction, spreads 

transmission costs over all users. In FERC-jurisdictionaiiSOs and RTOs, the formula in each case is a 

form of beneficiary pays where costs are recovered in the ISO or RTO tariff. Providing a mechanism for 

planning and cost allocation was a major reason for ISO and RTO formation and the creation of regional 

planning processes and tariffs has paid off. · 

Broad regional planning and cost allocation are the core elements of FERC Order No. 1000 and should be 

preserved and expanded, as discussed below. 

II. We have a long way to go 

Costly congestion remains on the system. Nationally, consumers are paying approximately $4 billion per 

year in the areas with Regional Transmission Organizations and Independent System Operators as 

shown in Table 1 below. Since those cover approximately two-thirds of the country, one could 

extrapolate to the rest of the country and infer that total is approximately $6 billion per year. 

2016 Annual Transmission Congestion Cost, in Transparent Markets• 

Region 

CAl SO 

ERCOT 

ISO-NE 

2016 congestion cost ($ million) 

142 

497 

39 

2 https://cdn.misoenergy.org/MTEP17%20MVP%20Trienniai%20Review%20Report11706S.pdf 

3 https://cdn.misoenergy.org/MTEP17%20MVP%20Trienniai%20Review%20Report117065.pdf 

4 https://www.iso-ne.com/staticassets/documents/2017/01/20170130 stateofgrid2017 presentation pr.pdf, pages 39-40 5 https://watttransmission.files.wordpress.com/2018/03/watt-living-grid-white-paper.pdf Appendix A. 

3 
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MISO 1,400 

NYISO 529 

PJM 1,024 

SPP 280 

Total 3,911 

Future projections of the US electric system find major opportunities for an expanded grid. A large 

consortium of grid operators, DOE national laboratories, and other researchers are currently developing 

an optimized national transmission expansion through the ongoing Interconnection Seams Study.6 The 

image below shows one grid configuration being considered where a major high voltage DC overlay is 

added to the current network. 

National laboratory Seams Study Transmission Scenario 

As indicated in the following table from a presentation of the study's preliminary results, these 

transmission investments yield benefits that are many times larger than their cost. The blue cells show 

the cost of each transmission addition, while the orange cells tally the benefits of that transmission. The 

bottom yellow cell calculates the benefit-to-cost ratio for each design, which range from 2.5:1 to 3.3:1 

depending on the design over a 15-year period. Benefits continue for the estimated 40 year lifetime of 

the transmission lines. Even without accounting for the cost of carbon emissions, the transmission 

investments were found to have a benefit-to-cost ratio of 2:1 or 3:1 over 15 years, depending on the 

design. 

6 https://www.nrel.gov/analysis/seams.html: preliminary results from "Interconnection Seams Study," 

presented at Energy Systems Integration Group spring meeting, March 2018 

4 
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Another study published in the journal Nature Climate Change examines the benefits of building an even 

larger nationwide transmission network that could save consumers as much as $47 billion annually, a 

roughly 10 percent reduction in electric bills. 7 

Other studies have looked at regional transmission investments. last year, the National Renewable 

Energy laboratory (NREl) released detailed analysis of several proposed transmission lines in the 

Western U.S., shown below. It found that these lines would cost $10 billion but save $2.3 billion per 

year,• which indicates the lines themselves would have a payback period of around 4 years. 

7 http://www.nature.com/nclimate/journal/vaop/ncurrent/full/nclimate2921.html. 

https://www.utilitvdive.com/news/study-deep-decarbonization-of-us-grid-possible-without-energystorage/412721/ 

8 https://www.nrel.gov/docs/fy17ostl/67240.pdf 

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In another regional study, Charles River Associates examined the potential for a high-voltage 

transmission overlay in SPP.9 1t concluded that the investment would provide economic benefits of 

around $2 billion per year for the region, more than four times the $400·500 million annual cost of the 

transmission investment. Of these benefits, $900 million would be in the form of direct consumer 

savings on their electric bills, with $100 million of these savings coming from the significantly higher 

efficiency of high-voltage transmission. The remainder would stem from reduced congestion on the grid 

allowing customers to obtain access to cheaper power. 

Synapse Energy Economics also analyzed the net benefits of a large transmission upgrade in the MISO 

footprint. This analysis found significant net savings for consumers from this transmission expansion, 

between $3 billion and $9.4 billion in net savings per year, or $63-200 in annual benefits per household 

in the region. 10 

Transmission investment is needed at a minimum to replace old transmission assets. like most 

infrastructure, this equipment will likely see a higher failure rate as it nears the end of its life, putting 

reliability at risk. Nationally, most of our transmission infrastructure was built between 1960 and 1980; 

according to one estimate, just replacing that infrastructure alone will cost around $8-14 billion per year 

over the next 25 years." A similar estimate is that the grid will need $57 billion over the next five years 

alone." Grid operators confirm that their transmission infrastructure is reaching the end of its life and 

must be replaced.13 As America undertakes that investment, it should also account for future needs and 

ensure that the size of transmission investment is optimized to realize the benefits outlined in this 

section. 

The vision of a high-capacity transmission network is being realized in other countries like China, India, 

and Europe. China is building a network of extra-high-voltage AC and DC transmission lines.14 The 800kV 

DC links have a capacity of around 8,000 MW, and China recently awarded a contract to build a 12,000 

MW 1,100 kV DC line, which will be a world record.15 For comparison, the DC Pacific lntertie that ties the 

U.S. Pacific Northwest to Southern California operates at 560kV and can carry up to 3,800 MW. 

9 CRA International, "First Two loops of SPP EHV Overlay Transmission Expansion: Analysis of Benefits 

and Costs," available at 

http:ljwww.spp.org/documents/8272/analvsis of benefits two loop sppfinal.pdf 

10 http://www.synapse-energy.com/sites/default/files/SynapseReport.2012-08.EFC .MISO-T-andWind.11-086.pdf 

11http:ljfiles.brattle.com{system/publications/pdfs/000/005/190/original/investment trends and fund 

amentals In us transmission and electricity infrastructure.pdf?1437147799. pages 6-7 

12 http:ljwww.cg-la.com//documents/Maximizing-the-Job-Creation-lmpact-of-%241-Trillion-inlnfrastructure-lnvestment.pdf 

13http:ljwww.nyiso.com/public/webdocs/media room/publications presentations/Power Trends/Pow 

er Trends/2016-power-trends-FINAl-070516.pdf, page 2 

14 https://www.windpowermonthly.com/article/1361466/analysis-china-adds-uhv-network-transfersurplus-wind-energy 

15 http:l/www.abb.com/cawp/seitp202/f0f2535bc7672244c1257ff50025264b.aspx 

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China's Transmission Grid Expansion Plan 

111. We should start by using the existing grid more efficiently 

As with most other forms of infrastructure, great advances in monitoring and control systems can 

improve electricity reliability and efficiency. Customers who are required to pay for transmission 

understandably want to assurance that the existing wires are being used to their maximum capacity. 

FERC and state regulators should first make sure that efficient, low cost solutions are deployed. 

There are a set of cost-effective technologies that can increase the flexibility, reliability and utilization of 

the existing grid. When Congress passed the Energy Policy Act of 2005 encouraging FERC to deploy 

advanced technologies, these network optimization options were not sufficiently developed for wide 

commercialization. They are now. 

A. Technology options 

leading technology options which can be used separately or together include: 

Dynamic Line Ratings 

The capacity of many transmission lines is limited by the temperature at which it can safely operate. 

Ambient temperature, sunlight, wind speed and direction, sunlight, and other weather factors that cool 

the lines can significantly increase their capacity. Dynamic line Ratings (DLR) increase capacity on 

existing transmission lines by calculating capacity ratings based on actual monitored conditions rather 

than fixed worst-case assumptions. With DLR, even relatively low wind speeds can significantly increase 

the rating of a line by cooling it, reducing the impact of curtailments and transmission congestion on 

customers and producers of wind energy. The benefits are particularly large for wind energy because 

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high wind speeds cooling the lines also increase the amount of wind electricity being generated and 

transmitted over the line. 16 

Estimates of Increased capacity have been 40 percent17, 30 to 70 percent, and 30 to 44 percent on three 

different tests.18 DLR systems also provide forecasted ratings up to 48 hours ahead. For the line shown 

in the chart below, the increase in capacity tends to be highest when congestion is highest. DLR systems 

also improve reliability by alerting operators to conditions such as line sag clearance violations if 

conditions are hotter and actual capacity on the line is lower than the fixed engineering estimates. 

Modeled Capacity in Kansas Transmission llne19 

DLR supports grid resilience by offering condition-based line capabilities when contingencies o.ccur. For 

example, when a line trips, the increased flow on other lines may be tolerable based on actual 

16 Doug Bowman and Jack McCall, "Reducing Contingency-based Windfarm Curtailments through use of 

Transmission Capacity Forecasting," CIGRE US National Committee 2017 Grid of the Future Symposium. 

https://watttransmission.files.wordpress.com/2017/11/reducing-curtailment-through-tcf-cigre2017-

bowman-mccall.pdf 

17Jake Gentle, Warren Parsons, Michael West, Catherine Meibner, Philip Anderson, "Increasing 

Transmission Capacities By Dynamic Line Rating Based on CFD." 

https :/ /watttransmission.files. wordpress.com/2017 /11/2015 _awe a_ dlr _ validation_final.pdf 

18 US Department of Energy, Dynamic line Rating Systems for Transmission 

lines, https://www.smartgrid.gov/files/SGDP Transmission DLR Topical Report 04-25-14 FiNALpdf, 

April2014, https://www.smartgrid.gov/files/SGDP _Transmission_DLR_Topicai_Report_04-25-

14_FINAL.pdf 

19 Verga, N. Pinney, and J. Marmillo, "Incorporating Dynamic Line Ratings to Alleviate Transmission 

Congestion, Increase Wind Resource Utilization. and Improve Power Market Efficiency," CIGRE US 

National Committee 2016 Grid of the Future Symposium. 

https://watttransmission.files.wordpress.com/2017/11/cigre-gotf-2016-genscape-finalsubmissionl.pdf 

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conditions even if the static, worst case assumption-based setting would lead to a protective action to 

trip the line. Relays could be programmed to take actual conditions into account. 20 

DLR technology can be rapidly deployed as it is minimally invasive and usually does not require deenerglzation of transmission lines and the resulting complex outage coordination required. A variety of 

systems have been demonstrated, including directly measuring line temperature and other properties, 

and in a non-contact form, measuring line Electromagnetic Fields (EMF). 21 

DLR has been deployed on a large scale in Europe. Belgium's Transmission System Operator Ella 

deployed systems on all of its critical overhead lines to France and the Netherlands, helping it maximize 

import capability after the retirement of three large power stations. 22 

Advanced Power Flow Control 

Power Flow Control refers to a set of technologies that effectively push or pull power away from 

overloaded lines and onto underutilized corridors within the existing transmission network. Advanced 

power flow control provides this same function with advanced features such as the ability to quickly 

deploy, easily scale to meet the size of the need, or redeploy to new parts of the grid when no longer 

needed in the current location. 

Topologv Optimization 

Transmission topology optimization is a software technology that automatically identifies 

reconfigurations of the grid to route power flow around congested or overloaded transmission 

elements, taking advantage ofthe meshed nature of the power grid. The reconfigurations are 

implemented through switching on/off existing high voltage circuit breakers. By more evenly distributing 

flow over the network, topology optimization increases the transfer capacity of the grid. Acting as a grid 

configuration "search engine," topology optimization can reduce congestion by up to 50 percent and 

improve response to contingencies, supporting reliability and resilience." It can reduce renewable 

20 J.C. McCall, T. Goodwin, "Dynamic line Rating as a Means to Enhance Transmission Grid Resilience," 

CIGRE US National Committee 2015 Grid of the Future Symposium. 

21Marmillo, N. Pinney, B. Mehraban, S. Murphy, "A Non-Contact Sensing Approach for the Measurement 

of Overhead Conductor Parameters and Dynamic line Ratings," CIGRE US National Committee 2017 Grid 

of the Future Symposium, https:/ /watttransmission. files. wordpress.com/2017 /11/gensca pe-cigre-gotfwhitepaper-2017.pdf 

22 Bourgeois, Raphael and lambin, Jean-Jacques, "Dynamic Ratings Increase Efficiency," T&D World, 

4/4/2017. http://www.tdworld.com/print/32183 

23 Pablo A. Ruiz, "Transmission Topology Optimization Software- Operations and Market Applications 

and Case Studies," ERCOT Emerging Technologies Working Group Meeting, Austin, TX, December 2016, 

http://www.ercot.com/content/wcm/key_documents_lists/85542/0S._Transmission_topology_control_ 

--_ERCOT_ETWG_12616.pdf 

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energy curtailment by up to 40 percent. 24 Optimization methods are much cheaper than hardware 

options such as phase angle regulators (PARs).25 

Storage 

Battery and other forms of storage can alleviate transmission congestion through charging and 

discharging at either side of a constraint. While storage can only move power over time and not space, 

and therefore is not a total replacement for all transmission needs, it can shift flow to times when 

congestion is less pronounced. It is very often the case that congestion changes over the timeframe that 

storage sources can store energy. Helping to alleviate transmission congestion or defer essential 

transmission upgrades is one of the many uses of storage technologies. 26 

B. Policies to Promote Advanced Transmission Technology Deployment 

Deployment of the technologies described above requires some action on an important piece 

of unfinished implementation business in The Energy Policy Act of 2005. The Act states that "In 

carrying out the Federal Power Act (16 U.S.C. 791a et seq.) and the Public Utility Regulatory 

Policies Act of 1978 (16 U.S.C. 2601 et seq.), the Commission shall encourage, as appropriate, 

the deployment of advanced transmission technologies:m The Act provided for incentives to 

"encourage deployment of transmission technologies and other measures to increase the 

capacity and efficiency of existing transmission facilities and improve the operation of the 

facilities." (italics added) FERC implementation of this Act focused on grid expansion and has 

yet to address the operations part of the job. 

The Commission, to its credit, has recognized this gap. After five years of experience with 

Order No. 679 which implemented this Act the Commission undertook a review. In a Notice of 

Inquiry the Commission observed "To date, the vast majority of applications for transmission 

incentives filed with the Commission have focused on the enlargement of facilities, including 

construction of new transmission facilities. Few applications have focused on the 

improvement, maintenance, and operations of transmission facilities or on increasing their 

capacity or efficiency ... For example, this could include software improvements that enhance 

scheduling and dispatch or investment in tools to enhance self-healing grid capabilities or 

24 Pablo A. Ruiz, Michael Caramanis, Evgeniy Goldis, Xiaoguang Li, Keyurbhai Patel, Russ Philbrick, Alex 

Rudkevich, Richard Tabors, Bruce Tsuchida, "Transmission Topology Optimization- Simulation of 

Impacts in P JM Day-Ahead Markets," FERC Technical Conference on Increasing Market Efficiency 

through Improved software, Docket ADl0-12-007, Washington, DC, June 2016, 

http:ljnewgridinc.com/wp-content/uploads/2016/06/PRuiz-FERCTechConf-28Jun2016.pdf, slide 11. 

25 T. Bruce Tsuchida, Xiaoguang Li, Pablo A. Ruiz, "Reducing Renewable Curtailments Through Flexible 

Operation," North American Wind Power, Feb 2014, pp. 10-12. 

https://nawindpower.com/online/issues/NAW1402/FEAT_03_Reducing-Renewable-CurtailmentsThrough-Fiexible-Operation.html 

26 http://energystorage.org/ energy-storage/technology-applications/tra nsmlssion-support-andavoidance-congestion-charges 

"EPAct 2005, Section 1223, Title 42 U.S. Code § 16422, Chapter 149, Subchapter XII, Part A (2005). 

10 
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improved situational awareness."28 The inquiry led to a policy statement that clarified FERC's 

incentive policy for grid expansion related issues, but not grid utilization. It acknowledged once 

again the issue: "Investments in the following types of transmission projects may face the types 

of risks and challenges that may warrant an incentive ROE based on the project's risks and 

challenges that are not either already accounted for in the applicant's base ROE or could be 

addressed through risk-reducing incentives: ... 3. projects that apply new technologies to 

facilitate more efficient and reliable usage and operation of existing or new facilities ... Examples 

of projects that meet this description include those that create additional incremental capacity 

without significant construction (e.g., through the use of dynamic line rating}, that allow for 

more efficient balancing of variable energy resources, and/or that provide increased grid 

stability. In addition, the Commission is concerned that its current practice of granting 

incentive ROEs and risk-reducing incentives may not be effectively encouraging the deployment 

of new technologies or the employment of practices that provide demonstrated benefits to 

consumers. Accordingly, the Commission remains open to alternative incentive proposals 

aimed at supporting projects that achieve these ends." 

The Commission has attempted to include transmission utilization technologies in its planning 

requirements. In the Commission's major reform of Open Access Transmission Tariffs in Order 

No. 890 in 2007, it stated: 

"Through the regional transmission planning process, public utility transmission providers 

will be required to evaluate, in consultation with stakeholders, alternative transmission 

solutions that might meet the needs of the transmission planning region more efficiently or 

cost-effectively than solutions identified by individual public utility transmission providers in 

their local transmission planning process .... When evaluating the merits of such alternative 

transmission solutions, public utility transmission providers in the transmission planning 

region also must consider proposed ... alternatives on a comparable basis. If the public 

utility transmission providers in the transmission planning region, in consultation with 

stakeholders, determine that an alternative transmission solution is more efficient or costeffective than transmission facilities in one or more local transmission plans, then the 

transmission facilities associated with that more efficient or cost-effective transmission 

solution can be selected in the regional transmission plan for purposes of cost allocation.''29 

Later in the Commission's major reform of regional transmission planning in Order No. 1000, it 

reinforced this Order No. 890 requirement: 

"However, we note that in Order Nos. 890 and 890-A, as well as in orders addressing related 

compliance filings, we have provided guidance regarding the requirements of the Order No. 

890 comparability transmission planning principle. Specifically, public utility transmission 

providers are required to identify how they will evaluate and select from competing 

28 Promoting Transmission Investment Through Pricing Reform, May 2011, RMll-26, p.13. 

" Preventing Undue Discrimination and Preference in Transmission Service, FERC Order 890, P 148 (2007). 

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solutions and resources such that all types of resources are considered on a comparable 

basis."30 

Despite these attempts to address advanced transmission technology in its incentive and 

planning policies, the job has not been accomplished. Now that technologies have matured to 

a point that much more market potential exists, it is a good time for the Commission to rectify 

this gap and review its planning and incentives policies. This does not necessarily mean there is 

a need for more incentives (which are appropriately viewed with skepticism by customers), but 

rather better alignment of incentives. In transmission as with other regulated industries, the 

challenge of the regulator is to structure incentives and rules to lead regulated entities towards 

efficient outcomes. That alignment is not currently present on transmission operations. It 

would benefit customers to allow for technology improvements where the savings are shared 

between customers and shareholders. The Commission has ample authority to pursue such 

reforms. 

IV. Grid expansion policy improvements 

Along with improving grid operations, policy makers can build on the last decade's success in expanding 

the grid to further capture the benefits of a more national integrated grid through the following actions: 

A. Fix inter-regional planning and cost allocation 

Although FERC Order No. 1000 required neighboring transmission planning regions to coordinate 

planning, it has resulted in very little expansion of inter-regional grid capacity. Some of the problems 

include differences between regions in benefits metrics, criteria, and cost allocation policies. Since each 

region's approach is different, there is a "triple hurdle" where a project must clear three tests, one for 

each region, and one combined test. 

FERC can remedy the "triple hurdle" by harmonizing the different methods and criteria between each 

neighboring RTO. The Commission could also provide an affirmative obligation to identify and jointly 

evaluate alternatives proposed by stakeholders, remove exclusions on projects of certain voltage levels 

or project sizes, and require consideration of public policy requirements as part of the assumptions that 

go into planning models. FERC has sufficient existing authority to take this action. 

8. Improve federal backstop permitting 

After the 2003 blackout where transmission Infrastructure constraints were among the many 

contributing factors, this Subcommittee and Congress included a limited backstop permitting role for 

the federal government in Section 1221 of EPAct 2005. This authority has never been used. A couple of 

court decisions have raised uncertainty about how it can be applied. The program will likely be needed 

if we are going to create the robust inter-regional delivery capacity we need. Congress, DOE, and FERC 

could each play a role to clarify this authority and establish workable processes so that it can be used 

where needed. I recommend that for specific extra high voltage (e.g., 500kV and up), long distance lines 

that provide broad multi-state reliability benefits and long-term consumer benefits, where state 

approval has been withheld after thorough consultation, DOE and FERC should be encouraged to be 

"Order No. 1000, Transmission Planning and Cost Allocation by Transmission Owning and Operating Public 

Utilities, 136 FERC ~ 61,051, Par 155. https:j /www.ferc.gov/whats-new/comm-meet/2011/072111/E-6.pdf 

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willing to use the current authority. The current authority is still a meaningful amount. It is also 

important for Congress to clarify the authority in response to the court decisions. 

C. Require pro-active planning that captures all values af transmission 

Transmission planning, both within and across regions, tends to be reactive and fails to capture the 

range of benefits that new lines create. A study prepared by five universities for the Eastern 

Interconnection Planning Collaborative, National Association of Regulatory Utility Commissioners, and 

the Department of Energy found that traditional planning approaches are not adequate to achieve leastcost outcomes in light of the modern market and challenges in today's electric transmission system, 

including plant retirements, renewable integration, and changing environmental regulations." The 

study found that anticipatory transmission planning would, as compared to the outcome of traditional 

reactive planning, reduce total generation costs by $150 billion, increase interregional transmission 

investments by $60 billion, and achieve an overall system-wide savings of $90 billion. 

The WIRES group has provided a series of helpful white papers that provide guidance on how efficient 

planning can be performed.32 The basic formula is simple: 1) transmission should be pro-active, to build 

the transmission expected to be needed in the future with different resources and loads; and 2) 

transmission planning should consider all ofthe expected benefits including reliability and efficiency, 

with public policies taken into account. Failure of planners to either pro-active or consider all the 

benefits leads to underbuilding of transmission. 

One benefit oftransmission--connecting new generators and resource areas--is particularly 

disconnected from the rest of the transmission planning process. In its recent order on transmission 

interconnection queue reform, FERC provided many improvements to the process. But it did integrate 

planning and interconnection, and it did not require consideration of advanced transmission 

technologies as alternatives. Those issues remain to be addressed. 

Transmission planning can also be more efficient if done probabilistically (considering many future 

scenarios) rather than deterministically (with one or a small number of expected futures). Probabilistic 

methods that quantitatively account for uncertainty in the transmission planning process result in a 

larger and more optimal transmission build, saving consumers tens of billions of dollars relative to 

deterministic methods that fail to account for the value of transmission in providing flexibility and 

hedging against uncertainty. Moreover, the probabilistic method saved hundreds of billions of dollars 

relative to some deterministic planning methods that greatly underbuilt transmission. 33 

FERC can lead these changes, following three decades of Commission work to improve regional 

transmission planning: "Regional Transmission Groups" in the late 1990s, Independent System 

Operators and Regional Transmission Organizations beginning in the late 1990s, Order No. 2000 in 1999, 

Order No. 890 in 2007, and Order No. 1000 in 2013. 

31 See Eastern Interconnection States' Planning Council, Co-optimization of Transmission and Other Supply 

Resources (September 2013), available at http://pubs.naruc.org/pub/5360834A-2354-D714-51D6- AESSF431E2M. 32 See, eg, http://www.wiresgroup.com/docs/reports{WIRES LEI TransmissionBenefits Jan2018.pdf, 

http://www.wiresgroup.com/docs/reports{WIRES%20Brattle%20Report TransmisslonPianning June2016.pdf. 33 http:ljhobbsgroup.johnshopkins.edu/docs/FD Munoz Oissertation.pdf. page 102; 

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There is a role for the Department of Energy as well. Effective regional planning requires active 

engagement of stakeholders, especially states. States and other stakeholders can better participate 

with support for modeling and process facilitation, which are both strong capabilities of DOE. 

D. Improve federal agency coordination and transmission permitting 

On February 2, 2016, DOE published a Notice of Proposed Rulemaking titled Coordination of Federal 

Authorizations for Electric Transmission Facilities, which proposes a simplified Integrated Inter-Agency 

Pre-application (liP) Process for inter-jurisdictional engagement. The DOE should explain how the energy 

corridor designations mandated by Section 368 of the Energy Policy Act, which are under revision by the 

Bureau of Land Management (BLM) and the U.S. Forest Service (USFS), and the DOE's IPP Process will be 

integrated with one another. These agencies should identify transmission routes and paths that align 

with future energy resource areas that are expected to be developed in the near future and prioritize 

permitting and agency coordination. 

The administration can support infrastructure development with sound and strong implementation of 

the FAST/DRIVE Act. Subpart D of this Act includes the Federal Permitting Improvement Act that aims to 

improve the permitting process for major infrastructure projects, including transmission, costing $200 

million or more. The law establishes a federal interagency council chaired by a Presidential appointee to 

develop permitting performance standards, set deadlines, and enable the public to track the progress of 

major federal permitting actions. However, the provisions terminate seven years after enactment and 

should be made permanent. Administrative improvements such as deadlines, a single point of contact, 

enforcement oftimelines, and agency disagreement resolution are important activities that could speed 

up the decision-making process. National Environmental Policy Act (NEPA) review of clean energy 

transmission over federal lands should include the positive environmental benefits of the lines- e.g., 

supporting zero carbon electricity-- when considering alternatives. 

E. Harness the authority of the Power Marketing Administrations to build additional transmission 

The Power Marketing Administrations (PMAs), including Bonneville Power Administration, Western 

Area Power Administration, Southwestern Power Administration and Southeastern Power 

Administration, under the authority of DOE, own tens of thousands of miles of existing high-voltage 

transmission lines and have transmission financing and development authority. This massive existing 

transmission infrastructure and strong related authority should be harnessed to accelerate U.S. 

transmission development for new energy sources. 

PM As should be encouraged to partner with private developers, which allows private parties and not 

taxpayers to fund infrastructure development, while utilizing PMA assets and tools. Section 1222 of the 

2005 Energy Policy Act authorizes the Secretary of Energy, acting through WAPA or SWPA, to "design, 

develop, construct, operate, maintain, or own, or participate with other entities in designing, 

developing, constructing, operating, maintaining, or owning, an electric power transmission facility and 

related facilities" needed to upgrade existing transmission facilities owned by SWPA or WAPA or in 

connection with new facilities located in any state in which SWPA or WAPA operates. BPA has similar 

transmission development authority under the Federal Columbia River Transmission System Act. This 

authority has only been used once, and that action was recently terminated by mutual agreement of the 

parties. 

F. Couple DOE federal transmission planning with the Department of the Interior's development of 

federal renewable energy zones 

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Using authorities established by the Energy Policy Act of 2005, the administration should revise the 

energy corridor designations by prioritizing transmission that specifically links the DOl renewable energy 

zones to large population (load) centers throughout the western United States. As the DOl moves to 

streamline approval processes and identify lands targeted for renewable energy development, the BlM, 

USFS and DOE should leverage the work required by a landmark 2012 settlement agreement reached 

with a coalition of conservation organizations and a western Colorado county. The agreement requires 

changes to a Bush-era plan mandated by Section 368 of the Energy Policy Act of 2005 designating 

"energy corridors• in the West. As the DOl develops renewable energy zones, the BlM, the USFS and 

DOE should designate "renewable energy transmission" corridors to service those zones. 

G. Consider Public Financing to "Right-Size• Transmission 

Money is wasted when we build lines that are too small. Even in the best US example to date of proactive transmission planning of Texas Competitive Renewable Energy Zones, many of those lines are 

now oversubscribed, and it Is clear that it would have been better for customers to build the higher 

capacity option that was considered and rejected. There is solid and stable information on where 

resource areas exist so if we pro-actively build transmission to those areas, development will come and 

our children and their children will benefit from it. However there is often not private market interest in 

financing capacity that will be used years into the future. There is therefore a good economic policy 

argument for public financing to fund the "right-sizing," or a higher capacity version of a line that private 

parties are willing to partially fund. The co-funding by private parties provides an important check to 

ensure lines are valuable, and the public financing achieves the more efficient level. Public financing 

could take a variety of forms. 

V. Conclusion 

1 appreciate the Subcommittee's interest in this important topic. I hope it can support both better grid 

utilization and grid expansion with some of the ideas provided. 

15 
103 

Mr. OLSON. Thank you, Mr. Gramlich. 

And for the panel, we are having votes called within the next 10 

to 15 minutes, floor votes. We will have to basically go into recess. 

But until then, we will try to get through as many member questions as possible. We have 5 minutes to ask questions. 

Being the chairman, I am first. 

And you all know that I am a Texan. And you all know that Texans love to brag about fellow Texans. We say they done something 

good. They said that in Haskell, Texas. Haskell is the home of our 

former Governor, our current Energy Secretary, Rick Perry. He did 

something good with what is called Competitive Renewable Energy 

Zones. He used those to fix a problem he had in Texas, a big problem. 

We have a lot of wind power, but we have most power out west, 

rural Texas, where it is not needed. We need it in eastern Texas, 

central Texas, Houston, Dallas-Fort Worth, Austin, San Antonio. 

But that CREZ initiative is part of why, as Dr. Krapels said, 

Texas leads the Nation in wind power. In fact, one day a couple 

years ago almost half our energy was provided by wind. Offshore 

Corpus Christi, Texas, that wind whips almost 300 days a year. We 

are making progress on that. 

My question is for you, Mr. Gramlich. Can you talk about how 

the CREZ model worked and whether that is something we could 

do elsewhere? 

Mr. GRAMLICH. Sure. And you are absolutely right, Congressman, 

the Texas CREZ model, as well as the ERCOT market structure 

overall, is a model for the country. 

I think we would be doing a lot better in all of the FERC jurisdictional areas if we essentially had the ERCOT market model 

throughout the Northeast and the rest of the RTO-ISO areas, as 

well as its proactive transmission planning model that has access 

to all of that wind and gas resources and others out in western 

Texas and the Panhandle. 

So essentially it is a simple formula of identifying where the generation resources are and proactively building to those resource. 

The alternative that is too often used in many other places is just 

to wait one by one for all the little projects to connect, and no one 

of them are going to build the transmission that are needed. So you 

need to proactively build and right-size the lines to the resource 

area. 

Mr. OLSON. Thank you. 

And, Doctor, would you like to add anything, Dr. Krapels, you 

are the wind expert, about the CREZ model in Texas, how that 

worked out? 

Mr. KRAPELS. I totally agree. And in the Northeast, we are looking at a wind resource offshore that could be 10,000 to 20,000 

megawatts. Texas size, Mr. Chairman. Texas size. 

Mr. OLSON. That is very big. 

Mr. KRAPELS. That is very big. 

Mr. OLSON. Huge. 

Mr. KRAPELS. It represents a capital investment opportunity of 

$30 billion, $40 billion, big even by Texas standards. And yet our 

transmission policy in the Northeast is the opposite of that of 

104 

Texas. It is let the generators build and own the transmission, 

which seems almost insane to me. 

We should do what Texas did. We should learn from Texas and 

build the transmission and plan the transmission first, and then let 

the generators compete like hell to get access to that transmission. 

That is what you did, and it works great. 

Mr. OLSON. This is a great hearing so far. 

The last question is for you again, Mr. Gramlich. 

You recently wrote a white paper about new technologies that 

can optimize a transmission system in a much lower cost than 

building new transmission lines. 

Can you briefly describe how that will work and compare that for 

the cost to the consumer, what the benefits are of your white 

paper, your plan? 

Mr. GRAMLICH. Yes. Thank you, Congressman, for the question. 

I formed a coalition called the WATT coalition, Working for Advanced Transmission Technology. And we put out a white paper 

where we were thinking, in part, about wholesale customers and 

thinking we do need more transmission, but we should also make 

sure that the existing grid is used as efficiently as possible. 

And many of these new technologies actually weren’t really commercially available when the Energy Policy Act directed FERC to 

promote them back in 2005. And so there is an unfinished chapter 

in the implementation of Congress’ act, and that is on the operational side, the utilization of the existing wires. A whole lot was 

done on incentives for new transmission, but nothing was done on 

utilization. 

And so, again, we are not asking for more incentives necessarily, 

just alignment of incentives and inclusion into the planning process. 

Mr. OLSON. Thank you. I am running out of time here. 

One question for you, Mr. Clark. I would be curious to know if 

you think regulators are doing a good job of keeping up with 

emerging technologies in the transmission or distribution space. 

Grade A, B, C, D, or something below that. 

Mr. CLARK. I would say it is incomplete, if that is an answer. 

Part of the challenge when we talk about regulators is you are 

looking at multiple jurisdictions of regulatory authority. So unlike 

the case of Texas where you have a wholesale regulator that is 

both the retail regulator and the wholesale regulator, for most of 

the rest of the country it is very difficult to bridge some of those 

divides. It is just the way the jurisdictional nature plays out. 

FERC has wholesale authority and interstate transmission authority. But many of those other decisions, regarding resource adequacy, integrated resource planning, retail decisions, are made at 

the State level. 

So it is tough to give an overall grade because of the natural jurisdictional divide that sometimes creates tension. 

Mr. OLSON. Thank you. My time has expired. 

It is now time for Mr. Rush, the ranking member of the subcommittee, to ask his 5 minutes of questions. 

You are up, sir. 

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

105 

Mr. Gramlich, as I mentioned in my opening statement, we are 

moving into a new energy paradigm where advanced technologies, 

such as distributed energy, microgrids, and energy storage are increasingly being developed and coming online. 

In your opinion, is Order 1000, as constructed, the best way to 

increase the deployment of these types of low-cost, clean energy resources? 

Mr. GRAMLICH. Sure. Thank you for the question. 

We are, indeed, moving toward that future of a more distributed 

network with many small, sometimes retail or State jurisdictional 

resources. I think the planning processes need to incorporate that. 

I do not agree with those who say that means we are not going 

to need as much of the bulk power grid. In fact, resources are still 

often variable and remote, and we need to move the power around 

geographically as well as over time, which storage can do. 

So we are going to need the big grid, so to speak, and we are also 

going to need much more coordination at the local level, which is 

really for State regulators to handle. 

I think reliability and efficiency can improve, however, if we 

bring those distributed resources into the wholesale markets. There 

are going to be a lot more resources available. And if there are any 

shortfalls, for example, if we give them access to the wholesale 

markets, we will have a lot more reliability. 

Mr. RUSH. Commissioner Clark, in your written testimony you 

stated that regions that are still served by vertically integrated 

utilities were already doing a fair amount of regional planning before Order 1000. And you maintain that Order 1000 actually replaced a collaborative, bottoms-up approach to transmission planning with more bureaucracy and a compliance checklist that may 

not necessarily result in additional transmission developments. 

Briefly, what recommendations would you suggest that would 

help improve Order 1000 to better achieve the goals of better process planning, better cost allocation, and increased competition, including for non-incumbent transmission developers? 

Mr. CLARK. Thank you for the question, Ranking Member Rush. 

What I would do for those, especially those regions of the country 

where—which is still the majority of the States—where the States 

maintain vertically integrated utilities, I would argue that Order 

1000 should be put on a pretty severe diet so that it is slimmed 

back in terms of trying to leverage those things that were working 

in the past. And you had indicated or referenced my testimony 

where I talk a little bit about this. 

A lot of the compliance obligations with regard to things like 

competitive bidding and the process that each of these regions have 

to go through, through that, don’t fit very well in regions of the 

country that are still vertically integrated. And the reason is because utilities working with their State utility commissions had always done that sort of regional planning in the past. And MISO’s 

MVP suite of projects was referenced earlier as a good example of 

how that worked well. 

Those types of projects we are not seeing coming forward anymore because now the name of the game is, well, we have to comply with Order 1000, and so it really just becomes a compliance exVerDate Nov 24 2008 13:48 Aug 08, 2018 Jkt 037690 PO 00000 Frm 00111 Fmt 6633 Sfmt 6633 I:\MY DOCS\HEARINGS 115\HEARINGS\115-127 CHRIS
106 

ercise as opposed to the more organic process that happened, bottoms-up. 

I think there are some different issues maybe in parts of the 

country that have restructured where you might have some natural 

tension between generation and transition as it relates to the marketplace. Even there I don’t think Order 1000 is working perfectly, 

as indicated by some of the examples that Dr. Izzo talked about. 

But at the very least in those vertically integrated regions of the 

country, I think it could be slimmed down from a compliance standpoint. Maybe focus more on some of the good aspects of regional 

planning and collaboration, and maybe especially on interregional 

projects where there may not have been as much conversation 

going on as there was after Order 1000. 

Mr. RUSH. I yield back. 

Mr. OLSON. Thank you. 

Mr. Long, 5 minutes for questions, sir. 

Mr. LONG. Thank you, Mr. Chairman, I appreciate you yielding 

to me. 

Mr. Twitty, FERC Order No. 1000 that is being discussed was an 

effort to introduce market concepts to transmission development. 

But the scope of transmission completion to date has been severely 

limited during implementation, forcing American businesses and 

households to overspend for transmission projects. 

Why is competition in this area so important? 

Mr. TWITTY. Well, I guess, Congressman—first, thank you for the 

question. We all believe that competition brings lower prices and 

better services. Whether that can happen in a commodity like 

transmission or, for that matter, other aspects of the electric business I think is still a question out for debate. 

I think it is clear that we have to pay more attention to how 

transmission gets built, how its ownership share is divvied up, 

what the rates of return are that are provided to the people who 

are building it. And as I have suggested, there are lots of folks out 

there who don’t have the opportunity to participate in the ownership and in some cases even the planning for these projects. 

I would suggest that if you really believe in competition, you 

really believe in having a grid that is right-sized, that everybody 

should be at the table. Whether we like Order 1000, the way it was 

written or the way it has been implemented, is a good question. 

Mr. LONG. You think it should be reexamined or—— 

Mr. TWITTY. Well, yes. I don’t think there is any—— 

Mr. LONG [continuing]. Repealed altogether? 

Mr. TWITTY. Yes. No. No. I think there are some good aspects to 

Order 1000, but I think it is not working the way it was intended. 

And if more people were part of the planning process, really a part 

of the planning process, really a part of the ownership structure, 

I think we would have a better outcome than we do today. 

Mr. LONG. According to your testimony, TAPS members in the 

Southwest Power Pool have seen an average annual rate increase 

of 17 percent for the last 5 years. That is annually. 

A few weeks ago the FERC Commissioner sat at the same table 

where you folks are sitting today, and I told him that your former 

employer, City Utilities of Springfield, has studies that show that 

costs are substantially higher than other customers in the SPP. 

107 

What needs to be done, either by Congress or by FERC, to fix 

this trend of such high annual rate increases for my constituents 

in Springfield, where you live? 

Mr. TWITTY. Well, I mention in my testimony the rates of return 

that are offered by FERC today are pretty attractive. I think we 

would probably all agree that if we had our 401(k)s and our IRAs 

invested at those guaranteed rates of return we would be pretty 

happy. 

So I think that needs to be addressed. As I suggested, I don’t 

think there is any need for incentives on top of those guaranteed 

rate of return. So I think that is a big piece of it. 

And the bottom line, as you mentioned, real customers paying 

real utility bills, like everybody in the room, pay these increases. 

And I would suggest that if it wasn’t for abnormally low natural 

gas prices today that are masking lots of these problems, people 

would be at your doorsteps wanting solutions and they would want 

them pretty doggone quickly. 

Mr. LONG. Talking about transparency for a moment here. How 

would greater transparency in the planning process of transmission 

building impact the cost of those transmission services? 

Mr. TWITTY. Well, I guess I think that by transparency we are 

including a number of things. If we have more people at the table 

who are actually using the transmission grid, I think it is going to 

help the right size grid be built. I think it is going to impact the 

siting process. I think Commissioner Clark mentioned earlier, the 

siting process is probably the most critical aspect of building any 

of these kinds of projects. 

I have been somebody that has knocked on people’s doors asking 

for rights of way. And I can tell you that if you have mayors, you 

have elected members of boards of public utilities, for instance, 

that are part of that process, it is going to be a better process, it 

is going to get the right thing built, it is going to be done as quickly 

as possible, and all of that translates into lower costs. 

Mr. LONG. You mention in your testimony that grid resilience 

should not be justification for excessive investment. In our recent 

hearings, the concept of grid resilience has been described as a crucial characteristic our energy system needs. 

Can you explain what you mean by that? 

Mr. TWITTY. Well, resilience seems to be the word of the day in 

our business. And there are so many risks, many of them presented 

through cyber threats, where we need to think about how the grid 

gets built and how the grid gets put back after an outage. 

We would probably all agree pretty easily on what resilience is, 

particularly those people who have been, like Dr. Izzo, running a 

utility today. 

But we shouldn’t let it be the end-all be-all to build something 

that you can’t cost justify. I used to say to our customers, look, we 

can guarantee your availability 100 percent of the time, but you 

couldn’t afford the service. And then later the engineers would say, 

well, we probably really can’t guarantee it 100 percent of the time. 

So it needs not to be an effort to gold-plate the system in the 

name of ‘‘it will never go down.’’ 

Mr. LONG. OK. Thank you. 

And it is good to see Chris here also today. 

108 

So I thank you all for being here. I yield back. 

Mr. OLSON. Thank you. 

Mr. McNerney, 5 minutes for questions, sir. 

Mr. MCNERNEY. I thank the chair on this. 

Mr. Krapels, your OceanGrid collector stations proposal for offshore wind is pretty interesting. What types of proposals have you 

seen outside of the New York-New Jersey area, including the West 

Coast, where we have deep water out there? 

Mr. KRAPELS. Thank you, Congressman. 

I have seen and studied very carefully what the European countries have done. So both Germany and the Netherlands are the 

leaders in offshore wind deployment. And in both of those countries, the idea of an OceanGrid that is separately owned has been 

part of the policy for some time, and it works very, very well. 

In California, I think it would be wise to look at the offshore in 

the same way that Texas looked at the upstate. It is a region with 

unlimited wind energy potential. 

Floating storage wind turbine technology is evolving so quickly, 

I think it will be economic within the next few years. And thinking 

about this from a grid standpoint, build a grid that maximizes the 

benefits to consumers, would be the right way to go. 

Mr. MCNERNEY. Thank you. 

Do we in Congress need to do something such as pushing the 

BLM’s offshore Federal land leasing to be structured so that neighboring wind farms can use the shared infrastructure? 

Mr. KRAPELS. I think that would be extremely helpful. Right now 

each wind generator can build its own transmission line to shore, 

but once they do that, that place on shore is occupied by that generator for the rest of time. So thinking it a little bit more holistically would be very wise. 

Mr. MCNERNEY. Thank you. 

Mr. Gramlich, you mentioned earlier that FERC does not need 

to grant more incentives, but to better align the incentives that we 

already have. What are your suggestions on how to go about doing 

that? 

Mr. GRAMLICH. Thank you, Congressman. 

There are examples from other countries that we are currently 

looking at and trying to work with a number of transmission owners on, as well as FERC staff and others. In the U.K., for example, 

when there is congestion, the transmission owner has an incentive 

to reduce that congestion, so thereby the savings are shared between customers and shareholders. 

So that concept, I believe, could be applied here in the U.S. It 

is not an easy task to implement these forms of performance-based 

regulation, but I am optimistic that with a lot of the best minds 

from the transmission industry and regulators we can figure it out. 

Mr. MCNERNEY. Well, I am kind of interested in the D.C. overlay 

idea. What would be the next steps to get that to happen? 

Mr. GRAMLICH. Number one, having people like you say that is 

an important thing to do. So thank you for that. Having FERC and 

the Department of Energy take interest. 

I do think there is a very interesting study that I cited in my 

written testimony called the Seams Study that a number of naVerDate Nov 24 2008 13:48 Aug 08, 2018 Jkt 037690 PO 00000 Frm 00114 Fmt 6633 Sfmt 6633 I:\MY DOCS\HEARINGS 115\HEARINGS\115-127 CHRIS
109 

tional labs are working on that has been partially released, but not 

fully released. 

That will be a great model. So when that comes out, I think facilitating a dialogue on how do we get that type of grid would be 

very worthwhile. 

Mr. MCNERNEY. Right. Well, you mentioned that there is a lack 

of private market interest in financing high capacity versions of the 

line, such as the Texas Competitive Renewable Energy Zones. Public financing to the right size may be appropriate. Can you discuss 

more about how such would be structured so that we don’t build 

excess capacity needlessly? 

Mr. GRAMLICH. Thank you for that. 

Yes, there is always a risk in regulated industries of overbuilding, and you need to think about that. But in this case we 

know where the resources are, right? The wind resources, the solar 

resources, geothermal, you name it. These are location-constrained 

resources that haven’t moved over generations and they are not 

going to move over generations. 

I submit we shouldn’t be that worried about overbuilding to access those resource areas. Our great, great, great, great grandkids 

are going to benefit from whatever we do to build out that network. 

Mr. MCNERNEY. Interesting. 

I am going to yield back in the interest of time, Mr. Chairman. 

Mr. OLSON. Thank you. 

As a reminder, votes are about to be called. My intention is to 

alternate between Republican and Democrat until we have to go 

vote. We will recess for maybe a half an hour or 45 minutes and 

come back. 

The next member to ask questions is Mr. Griffith from Virginia, 

5 minutes. 

Mr. GRIFFITH. Thank you very much. And in the interest of time, 

I am going to send some questions afterwards, as we are allowed 

to do within the next 10 business days, and I will do that. 

But I am going to ask one question live, Mr. Twitty, because I 

represent AEP country in southwest Virginia. And you mentioned 

that AEP’s zonal transmission rate has significantly increased, 

about 15 percent per year over the past 6 years. 

I am wondering if you can explain that to the folks back home. 

And then answer the question: That is obviously a significant increase for customers in my area. Are there sufficient consumer protections in place to prevent unnecessary investments in the future? 

So first explain why it is going up so much, if you can do it 

quickly, and then what do we need to protect folks. 

Mr. TWITTY. Well, I would answer it, Congressman, by saying, as 

I did to Congressman Long, it is too rich an investment for the people who own and build new transmission. It is too rich. We need 

to reduce returns on equity. We need to make sure we are not providing incentives on transmission investment for a run-of-the-mill, 

standard transmission line. That is certainly number one. 

Number two, as I have said, I think we need more people at the 

table from the very beginning. Owners of transmission need to let 

those of us who need the transmission to get their generation to 

load to be at that table and to own a load ratio share. 

110 

These are the people who represent customers, real customers, 

and if they are at the table, I think they are going to do a lot of 

good work to make sure that there is no gold-plating, there is not 

any overbuilding, that we build exactly what it is we need to get 

generation to load. 

It is a long process. It requires your influence on the FERC. It 

requires lots of people talking about these issues. It is easy to say 

we want somebody at the table. 

If you are a transmission owner, you want to be a transmission 

owner and do exactly what you want. If there are other voices at 

that table, it gets a little bit messier. I think you get a better product if that is what happens. 

Mr. GRIFFITH. Well, I appreciate that. 

And with that, Mr. Chairman, I will yield back so somebody else 

can get a question in. 

Mr. OLSON. Mr. Johnson, Mr. Long, Mr. Cramer, anybody want 

to question, yield, take the time? 

Mr. Johnson you are recognized. 

Mr. JOHNSON. Thank you. Thank you, Mr. Chairman. I will make 

these quick. 

Mr. Clark, one of the primary objectives of Order 1000 was to 

promote interregional transmission development. But there is 

broad consensus that Order 1000 failed to achieve that goal. 

So in your opinion, how could this objective be achieved? 

Mr. CLARK. Sure. I think part of it is, Congressman, and thank 

you for the question, part of it is, as I said, attempting to focus in 

on what you are actually trying to accomplish in the rule. The rule 

itself is expansive, it ran several hundred pages long, the compliance filings are probably thousands of pages on top of that. 

And I think part of the reason that you get that result is the 

order tried to do a lot of things all at once. It was partly competition policy. It was partly an investment policy. It was partly a regional planning policy. It was partly a cost allocation policy. Some 

of it dealt intraregional things, some of it interregional things. 

And when you push that much out in a rule and expect the regions to do something with it, you end up with, in my opinion, just 

a lot of bureaucracy and checking compliance boxes. That is why 

I say I think putting the order on a diet and trying to focus in on 

what you are really looking at doing probably would be the most 

helpful thing. Some of it may be reinforcing some of the planning 

conversations that happen, but without the more prescriptive elements of it. 

And I think part of it might be focusing more on the issue of 

interregional projects as opposed to spending a lot of time within 

these regions having to vet through and try to manage the type of 

intraregional projects that were happening organically prior to the 

order itself. 

Mr. JOHNSON. OK. What would be the advantages of greater 

interregional transmission? 

Mr. CLARK. Because you have an interconnected grid, both in the 

West and in the Eastern Interconnect, there may be certain 

projects that serve a broad regional benefit that have benefit that 

accrues to many times over. 

111 

But if you are only looking within your region, you might not see 

the value of the benefit of those particular lines. Some of them 

could be reliability lines. Some could be market efficiency lines. 

But some sort of process to have a yardstick to compare the 

interregional type of projects might be valuable, and that may not 

have been captured in earlier FERC orders such as 890. 

Mr. JOHNSON. All right. Thank you. I yield back. 

Mr. OLSON. Thank you, Mr. Johnson. 

Ms. Castor, 5 minutes, ma’am. 

Ms. CASTOR. Thank you, Mr. Chairman. 

Thank you to all the witnesses who are here today. 

We recently in the Oversight and Investigations Subcommittee 

had an oversight hearing on the state of the grid in Puerto Rico. 

I want to thank the committee for continuing to focus on our neighbors in Puerto Rico. 

Unfortunately, right after the Army Corps of Engineers and DOE 

testified that they thought they had things on track, they had a 

major outage again. So I would like to ask you all after to supplement the record with any recommendations moving forward there. 

Clearly, there is an issue on transmission and the need for 

microgrids and more resiliency there. 

But as we work to modernize the grid everywhere and deal with 

the cost of the changing climate and building greater resiliency, we 

need to make sure we are taking advantage of nontransmission alternatives, such as microgrid, distributed energy resources, and energy storage. 

Nontransmission alternatives not only have significant environmental benefits, but they can help prevent long-term area-wide 

blackouts after natural disasters, like we saw in Texas and Florida 

and Puerto Rico this summer. 

We also need to be focusing on the needs of consumers and be 

a lot smarter. These nontransmission alternatives can be a great 

benefit to consumers. FERC Orders 890 and 1000 recognize the 

benefits of nontransmission alternatives, requiring regional transmission plans to consider whether nontransmission alternatives 

can more efficiently, cost-effectively, meet the needs of a region. 

But despite all these benefits, these alternatives are not being 

utilized to the extent they should be, especially given how advanced the technologies have become. 

So, Mr. Gramlich and Mr. Twitty, do you think that if there was 

a stronger FERC order that required more than just consideration 

of alternatives, we would see greater use? And what are the barriers to broader deployment and utilization? 

Mr. GRAMLICH. I do. Thank you for the question. 

For reliability and resilience, you can improve both by better 

monitoring and control of the infrastructure. It seems obvious. We 

do it with just about every other form of infrastructure with better 

monitoring and control systems and computing power. All through 

our economy we have these opportunities to monitor and control 

better, and that helps with reliability as well as efficiency. 

So transmission is no different. The only problem is, it is a regulated industry, the incentives, as I said, are misaligned, and the 

planning requirements are not up-to-date with the new opportunities we have. 

112 

Ms. CASTOR. Mr. Twitty, short answer. 

Mr. TWITTY. Congresswoman, thank you for the opportunity to 

respond to that. I would certainly agree with those comments. 

And I would suggest, as somebody who used to have responsibility for keeping lights on, at the end of the day that is the most 

important thing that all of us are after. 

Technology is a wonderful thing. It marches along. And yet implementing it in the real world, getting the right kind of investment at the right time, is always going to be critical, and making 

sure it works as it relates to the total grid. 

It is one of the challenges today of intermittent resources. Wind 

and solar are wonderful, and we are all trying to figure out ways 

to harness them properly. But when the wind doesn’t blow or the 

sun doesn’t shine, it is a real challenge. 

So you have to have a system designed that can take this intermittent resource, and in the case of microgrids turn over control of 

a part of your grid to others. And for people, again, like Dr. Izzo, 

who have responsibility for keeping lights on today, that is a pretty 

nervous thing, because if it doesn’t work properly, if the technology 

isn’t fully baked, lights go out and—— 

Ms. CASTOR. Highlights the importance of planning and investments. Thank you so much. 

Mr. TWITTY. Exactly. 

Mr. OLSON. Thank you. And seeing there are no further members 

wishing to ask questions, I would like to thank our witnesses again 

for being here today. Thank you. Thank you. Thank you. Much 

obliged. 

Before we conclude, I would like to ask unanimous consent to 

submit the following documents for the record: a letter from 

GridLiance and a letter from WIRES. Without objection, so ordered. 

[The information appears at the conclusion of the hearing.] 

Mr. OLSON. And pursuant to committee rules, I remind members 

that they have 10 business days to submit additional questions for 

the record. I ask that the witnesses respond within 10 business 

days upon receipt of the questions. 

Without objection, this subcommittee is adjourned. 

[Whereupon, at 11:04 a.m., the subcommittee was adjourned.] 

[Material submitted for inclusion in the record follows:] 

PREPARED STATEMENT OF HON. GREG WALDEN

Good morning and welcome to our witnesses. Today’s hearing on transmission infrastructure is another important topic in the Energy Subcommittee’s Powering 

America series. I want to thank our witnesses for participating and I look forward 

to hearing your perspectives on the state of our nation’s electric transmission infrastructure. 

The United States’ electricity system is one of our nation’s more impressive engineering feats—with its interconnected network of power plants, poles, and wires 

that delivers uninterrupted electricity from producers to consumers. Transmission 

is an integral component of our electricity system. Often called the bulk-power system, transmission infrastructure enables the movement of electricity across states, 

regions, and the country as a whole. However, as time passes and transmission infrastructure ages, upgrades and replacement of existing infrastructure, as well as 

capital investments in new projects are necessary to ensure electricity is delivered 

in a reliable, efficient, and cost-effective manner. 

Like many energy infrastructure projects, the construction of new transmission infrastructure can face difficulties, in part due to lengthy delays in permitting and 

113 

siting processes. Energy infrastructure projects such as natural gas pipelines and 

LNG facilities are subject to Federal Energy Regulatory Commission (FERC) permitting processes. On private lands, utilities, grid operators, or states make the decision on whether a new transmission line needs to be built and whether to upgrade 

existing transmission infrastructure. However, when it comes to siting and building 

transmission lines across Federal lands, the Department of Energy is the lead agency in coordinating all applicable Federal authorizations and related environmental 

reviews of electric transmission facilities, with some authorities delegated to FERC. 

Consistent with the intent of the Administration’s recently announced MOU on 

implementing One Federal Decision, agencies must work together to provide a more 

predictable, transparent, and timely Federal review of infrastructure projects. 

Through the Federal Power Act, Congress gave FERC the authority to regulate 

the sale and transmission of electricity in interstate commerce. Under this authority 

the FERC issued a series of rules to oversee and regulate the regional and interregional planning of transmission projects while at the same time encouraging 

greater competition between transmission developers. FERC’s most recent rule on 

transmission was in 2011, with Order 1000. Today’s hearing will explore these rules 

and the related challenges of transmission planning. 

This Committee has discussed at length the importance of utilizing digital and information technologies for a more dynamic and innovative electricity system. 

Through previous Powering America hearings, we have focused on energy technologies located at the distribution level of the electric grid. However, new technologies have the potential to optimize the Nation’s electricity system at the bulkpower level. 

Advanced grid technologies can modernize transmission infrastructure to ease 

congestion, allow for increases in demand, and provide greater security. These smart 

technologies include sensors for measuring system conditions, electric power equipment that regulates power flow, and computerized monitoring equipment that enable system operators to view the electric grid in real time and make necessary adjustments. 

For example, these technologies can optimize the flow of electricity by automatically routing power around overloaded or congested lines—allowing for greater line 

capacity. High voltage direct current transmission lines can be a less expensive alternative and have less electrical losses compared to traditional alternating current 

lines in transmitting electricity over long distances. I look forward to hearing more 

from our witnesses today on how these advanced technologies have the potential to 

optimize transmission infrastructure at the bulk-power level. 

The Nation’s transmission system is a vital component in the safe, reliable, and 

affordable delivery of electricity to consumers across the country. We must ensure 

that the electric grid works in ways that integrate new technologies within existing 

transmission infrastructure, and siting new infrastructure when needed. Thank you 

to our witnesses for joining us today and I look forward to your testimony. 

114 


30978.084

J. CALVIN CROWDER 

President & CEO 

May 9, 2018 

The Honorable Fred Upton 

Chairman, Subcommittee on Energy 

House Committee on Energy and Commerce 

2125 Rayburn House Office Building 

Washington, DC 20515 

Dear Chairman Upton and Ranking Member Rush: 

The Honorable Bobby Rush 

Ranking Member, Subcommittee on Energy 

House Committee on Energy and Commerce 

2125 Rayburn House Office Building 

Washington, DC 20515 

As one of the nation's leading independent transmission developers, GridLiance applauds you 

for convening this week's hearing on the state of electric transmission infrastructure, including 

the challenges associated with the planning and construction of new transmission lines, among 

other issues. A portfolio company of Blackstone Energy Partners, GridLiance's differentiated 

business model is to work with electric cooperatives, municipal utilities, irrigation districts, and 

joint action agencies to help them plan for the future, invest with them or for them in electric 

transmission infrastructure, and implement strategies that meet their ownership, capital 

investment, and operational goals. 

We appreciate the opportunity to provide the following views on the state of competition for new 

transmission construction introduced by the Federal Energy Regulatory Commission (FERC)'s 

landmark Order No. 1000, including aspects where implementation ofFERC's competitive 

transmission reforms can and should be improved. 

As discussed in your staffs memorandum of May 8; 2018, Order No. 1000 was an effort to 

introduce market concepts to transmission development. This effort is vital to ensuring that 

transmission investment decisions are as efficient as possible. Competitive forces have proven 

phenomenally successful in the electric generation sector, and if unleashed for electric 

transmission these forces can produce similarly impressive results. However, despite FERC's 

best intentions, the scope of transmission competition to date has been severely limited during 

implementation, forcing American households and businesses to overspend for transmission 

projects. Although the Commission appropriately sought to optimize transmission additions 

through the planning requirements of Order No. 1000, the misguided desire to avoid a 

competitive mandate has led to an explosion of local transmission additions being constructed 

outside the regional planning processes in an effort by incumbents to avoid those very 

competitive forces that will produce more efficient infrastructure. Likewise, exploitation of 

exceptions to competition, whether included in Order No. 1000 initially or added through 

compliance filings, have further limited the value of ratepayers' transmission expansion dollars. 

These exceptions have now limited competition to a tiny fraction of new transmission spend in 

most RTOs. For these reasons, the needed transmission system buildout occurring today is 

increasingly being sub-optimized at customers' expense. 

As the Subcommittee seeks to understand how it can ensure that the grid continues to respond to 

the rapidly changing conditions in the industry, we believe it is important to keep in mind three 

fundamental principles: 

201 E. John Carpenter 

Frwy; Suite 900 

Irving, TX 75062 

1701 Pennsylvania Ave, NW 

Suite 200 

Washington, DC 20006 
115 


30978.085

l. It is critical for PERC to acknowledge that in expanding and modernizing the U.S. electric 

transmission network as necessary to meet resilience needs, competition can play a key role 

in delivering greater resilience benefits for fewer customer dollars. Competitive forces 

introduced by Order No. 1000 have proven to be an effective means of ensuring that the cost 

of new transmission construction required to meet ongoing grid resilience and reliability 

challenges are minimized for customers, without short-changing grid reliability. Where the 

competitive principles of Order No. l 000 have not been employed, ratepayers pay higher 

rates for transmissiol). For example: 

Competition has led to proposals from companies containing cost caps that shift the 

cost risk for new transmission from ratepayers to project developers, more technically 

innovative solutions to adding transmission capacity, and reliability and construction 

quality comparable to incumbents. 

Contrary to claims from the rule's detractors, the costs to administer Order No. 1000 

proposal windows are relatively low, especially compared to the documented savings 

for customers. 

2. Adequate transmission solutions can create an electric grid that is more resilient to a wider 

variety of disruptive events. But simply rebuilding the electric grid of the last century 

through the guise of "asset management" or end of life criteria without analyzing whether 

that grid provides the resiliency resources for a new century, leaves grid planners and the 

Commission with transmission infrastructure that may not meet optimal or desired needs of 

consumers, and most importantly leaves ratepayers bearing the consequences of uneconomic 

decisions. 

3. Getting the niles right on transmission development also requires that capitalized 

transmission owner "local" or "maintenance" projects that upgrade capacity, change voltage, 

or increase a line rating are developed and constructed through a PERC-approved open, 

coordinated, and transparent local or regional planning process. GridLiance applies the same 

standard to its planned capital maintenance program. 

Thank you again for your consideration of these important topics. We look forward to 

continuing to work with the Subcommittee on these issues moving forward. 

Sincerely yours, 

Calvin Crowder 

President and CEO, GridLiance 
116 


30978.086

May9,2018 

via Email CEnergy.commerce@mail.house.gov) 

Frederick S. Upton, Chairman 

Bobby L. Rush, Ranking Member 

Members of the Subcommittee 

Subcommittee on Energy, Committee on Energy and Commerce 

Rayburn House Office Building, Room 2125 

Washington, DC 20515 

Dear Chairman Upton, Ranking Member Rush, and Members of the Subcommittee: 

Thank you for including these brief observations in the record of your hearing of May 10, 2018. 

Investment in transmission infrastructure is a subject of major national importance to which little attention 

is ordinarily paid and I therefore commend your efforts to elicit the best thinking on the subject. 

Based on my years of experience in the energy area and my tenure leading the FERC, I can assert that no 

organization is more dedicated to promoting investment in the electric grid, modernizing its technology, 

or improving its regulation than is my client WIRES, a non-profit international trade association 

(www.wiresgroup.com). WIRES has produced for policy makers like yourselves and the industry a 

battery of studies on how transmission benefits North American economies and consumers, and how 

transmission, if made sufficiently robust, can ensure that we meet the challenges of an economy that is 

destined to be much more highly electrified in the coming decades. I am attaching for your review the 

comments we just filed at the FERC about why transmission investment is critical to the resilience of our 

electric system. 

Let me share brief observations about the topics of your hearing. First, the level of transmission 

investment in recent years essentially made up for a quarter century of underinvestment, replaced aging 

and electro-mechanical facilities (some nearing a century old), and addressed short term reliability issues. 

We should not allow ourselves to rest on our laurels, however. Continued investment is not optional if 

we are to meet challenges of an electrifYing economy, install modem digital technologies, deploy and 

serve more distributed resources, enhance regional and interregional energy markets, lower electricity 

prices for consumers (which are a declining share of the cost of living almost everywhere), and 

strengthen the grid against physical, cyber, and natural disruptions. The high-voltage grid must be stormhardened and modernized for an environment that can be hostile to our electrified society- that's where 

we urge the FERC to expend it resources and authority. 

Second, no energy delivery system is more extensively planned, more regulated and overseen at more 

levels of government, or more resisted based on misconceptions about who these facilities benefit than is 

the transmission grid. The reasons for this are partly historical; we are building an integrated, regional 

and multi-state network under laws and a jurisdictional division of labor based on a completely outdated 

business model of local and state monopoly. Compared to the 3-4 years needed for natural gas pipelines 

for example, the planning, siting, permitting, and construction of transmission lines frequently require a 

decade or more. Uncoordinated environmental reviews are a small part of the problem, in my estimation. 
117 


30978.087

The more important and extensive a project is, the more likely that affected states will fall into prolonged 

disagreement about who benefits and how the public interest should be served. It's an old story with no 

solution on the horizon- at least not without your help. 

Order No. 1000 has been part ofFERC's plan to move toward a more integrated, market-friendly bulk 

power environment. It has many critics. Some of the criticism that it has not yielded the transmission 

infrastructure it promised, commensurate with its administrative burdens, is entirely justified. I, for one, 

think its failure to produce more interregional projects to sustain broader markets is a major problem. 

However, the Commission appears to have taken a pass on opportunities to make the rules simpler, 

clearer, and more productive. Instead it has deferred to states and regions to develop their unique 

approaches, in effect perpetuating the patchwork of tariffs, rules, and procedures that critics complain 

about. But I hasten to add that Order No. 1000 instituted the regionalization of grid plarming and 

allocation of costs to true beneficiaries that are, and should remain, the touchstones of grid regulation. It 

has generated many successes, and now we should move beyond it. Nevertheless, the public and industry 

would be well served if FERC took a fresh look at its long-term electricity market objectives and began 

down the road to major improvements to what is already on the books. 

Finally, the decentralization of electric generation resources and the new technologies that empower 

individuals and businesses to be energy providers and price setters as well as consumers and price takers 

do not spell the end of the wired network of transmission lines. Those resources and technologies will 

depend more than ever on the grid for their economic justification and deployment. Transmission gives 

us the optionality to adapt electrically to whatever the future holds. Made smarter and more resilient, the 

transmission system will be the most valuable energy asset we have. 

Thank you Mr. Chairman and Members of the Committee for your consideration. 

With kind regards, 

~.._ 

James J. Hoecker 

Executive Director and Counsel, WIRES 

Enclosure: Comments of WIRES filed in FERC Docket No. AD18-7 -000 

Cc: Jason Stanek (via Email) 

Senior Counsel, Committee on Energy and Commerce 
118 


30978.088

GREG WAlDEN, OREGON 

CHAIRMAN 

ONE HUNORED FIFTEENTH CONGRESS 

FRANK PAllONE, JR., NEW JERSEY 

RANKING MEMBER 

€ongress of tbe Utniteb ~tatts 

~out of 1\,tprt!ltntattbei 

COMMITTEE ON ENERGY AND COMMERCE 

2125 RAYBURN House OFFICE BuilDING 

WASHINGTON, DC 20515-6115 

The HO!!Orable Tony Clark 

Senior Advisor 

Wilkinson Barker Knauer, LLP 

1800 M Street, N.W.; Suite SOON 

Washington, DC 20036 

Dear Mr. Clark: 

Majority {202l22!i~29t1 

Minority t202) 225-3641 

June5,2018 

Thank you for appearing before the Subcommittee on Energy on Thursday, May 10, 2018, 

to testify at the hearing entitled "Examining the State JlfBlectric Transmission lnftoastructure: 

Investment, Planning, Construction, and Alternstives." 

Pursuant to the Rules of the Committee on Energy and Commerce, the hearing record 

remaios open for ten bnsiness days to permit Members to submit additiJlnal questi!lns for the record, 

which are attached. To facilitate the printing of the hearing teCJ)rd, please respond to these questions 

with a transmittal letter by the close of business on Tuesday, June 19, 2018. Your responses should 

be mailed to Kelly Collins, Legislative Clerk, Committee on Energy and Commerce, 2125 Rayburn 

Honse Office Building, Washington, DC 2051 S and e-mailed in Word format to 

Kelly.Collins@mail.bouse.20V. 

Thank you agaio for your time and effort preparing and delivering testimony before the 

Subcommittee. 

cc: The Honorable Bobby L. Rush, Ranking Mernber, Subcommittee on Energy 

Attachment 
119 


30978.089

The Honorable Fred Upton 

Chairman, Subcommittee on Energy 

June 19,2018 

U.S. House of Representatives Committee on Energy and Commerce 

2125 Rayburn House Office Building 

Washington, DC 20515-6115 

Dear Chairman Upton, 

Thank you for the invitation to testify before your Committee on May l 0, 2018, at the hearing 

entitled, "Examining the State of Electric Transmission Infrastructure: Investment, Planning, 

Construction and Alternatives." 

Enclosed are my responses to the questions for the record that were provided to me earlier this 

month. 

Please do not hesitate to contact me if I may be of further assistance. 

Sincerely, 

Is/ Tony Clark 

Senior Advisor 

Wilkinson Barker Knauer LLP 
120 


30978.090

The Hon. Fred Upton 

1. In your testimony, you said that transmission incentives may be ripe for review. As you know, 

the Energy Policy Act of 2005 directed FERC to create a program to award certain 

transmission rate incentives to transmission projects that qualified under the regime known 

as Order 679. 

a. What type of review do you think FERC should conduct on transmission incentive policy? 

Five years after Order No. 679, FERC undertook a Notice of Inquiry that resulted in the 

2012 Policy Statement that provided further guidance regarding the Commission's 

implementation of Order No. 679. It has now been over five years since the 2012 Policy 

Statement and there has been significant industry, regulatory and legal activity in the 

transmission space. I would suggest that given the number of transmission items sitting 

squarely before the Commission, including various court remands, now may be an 

opportune time to look at FERC transmission policy (including ROE policy and 

incentives) holistically. A Notice oflnquiry could be one vehicle for the Commission to 

begin that sort of dialogue, but the Commission has a number of regulatory tools to 

initiate a conversation on these matters. 

b. Is there anything Congress should do to amend the Federal Power Act? 

I do not have any suggestions for specific Congressional action in this regard. 

2. As you know, the regulatory process for settling disputes over the appropriate base rate of 

return on equity for transmission was thrown into question by a D. C. Circuit decision more 

than a year ago. To date, this issue has yet to be addressed by FERC on remand. 

a. With no regulatory certainty with regard to FERC's overall ROE policy, how is this 

affecting transmission development and financing. 

There are a number of outstanding court remands that are being watched by the 

transmission industry. These include the D.C. Circuit Court opinion you reference, as 

well as a separate decision from California related to the Commission's incentive ROE 

adder routinely granted to utilities for joining Regional Transmission Organizations. 

Both transmission owners and transmission customers are very much interested in the 

outcome of these proceedings given the regulatory uncertainty that exists during their 

pendency. 

b. Do you see a chilling effect on investment at a time when the nation needs new 

transmission irifi'astructure? 

As a general matter, regulatory certainty in such matters lends itself to timely decision 

making with regard to capital outlays. Conversely, long-term uncertainty lends itself to 

indecision. 
121 


30978.091

The Hon. Gregg Harper 

1. The Committee has concerns that FERC's current application of the discounted cash flow 

(DCF) methodology for transmission ratemaking is not having the intended effect to attract 

capital and deploy critical new transmission infrastructure. 

a. Would you agree that DCF, as currently utilized by the Commission, is underperforming 

with respect to achieving these objectives? If so, why do you believe this is the case? 

In 2014, the Commission released Order No. 531, which adopted a two-step DCF 

methodology similar to that used by FERC when establishing natural gas pipeline rates. 

Included in Order No. 531, was a Commission determination to select the midpoint of the 

upper half of the zone of reasonableness for setting base rates, due to unusual capital 

market conditions. FERC, however, was not successful in defending Order No. 531 

before the D.C. Circuit Court of Appeals, so the current and future status of the DCF 

methodology's performance is the subject of much uncertainty. 

b. Do you believe FERC 's current application of the two-step DCF model should be 

reevaluated? Should the Commission review the assumptions and data inputs that form 

the basis of its two-step DCF model? 

With the court remand of Order No. 531, I believe the time is now ripe for the 

Commission to consider many transmission investment issues holistically. This review 

could include consideration of the mechanics of the DCF methodology, transmission 

incentives, and the decision making process the Commission employs when deciding 

whether to send a transmission compliant to hearing. 

c. What, if any, "fixes" to the Commission's application of DCF might FERC consider? 

Also, what, if any, alternative models or methodologies might the Commission consider 

in lieu of in or in addition to the DCF model to better account for factors and conditions 

not considered by the DCF model, including measures of capital market risk? 

Should the Commission choose to change its ROE-setting methodology, yours is among 

the most difficult questions the Commission will attempt to answer. Unfortunately, there 

is no simple answer and no silver bullet. 

Consistent with Congress' directives and the Federal Power Act, FERC should ensure 

that any methodology it chooses results in ROEs that are appropriately constructive to 

transmission investment. Commission policy needs to provide a relatively stable and 

predictable methodology for calculating ROEs while not being so rigid that it precludes 

the Commission from ensuring that transmission investment remains appropriate in 

changing economic conditions. 

Any change will inevitably result in litigation and, as the court remand in Order. No, 531 

proves, persuading a court when making a regulatory policy shift can prove challenging. 

If the Commission determines its existing methodology no longer produces just and 
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reasonable returns given the investment risk associated with constructing transmission, 

there are several refinements the Commission could consider, including different models 

for ROE-setting that are employed by regulatory bodies both in the U.S. and 

internationally. 

The Commission will also need to decide how it would implement a change in policy. In 

Order No. 531 it altered the methodology via a contested complaint case, but the 

Commission could also choose to open a broader inquiry through an industrywide 

rulemaking proceeding. Each approach has its advantages and disadvantages which the 

Commission will want to assess. Regardless of if or how the Commission chooses to 

proceed, one recommendation I have is for the Commission to be as diligent as possible 

in how it communicates any changes to the broader stakeholder community. Regulatory 

surprises should be avoided since they can have unintended consequences on the entire 

utility sector and unduly chill needed investment. 

The Hon. Richard Hudson 

On Apri/19, PERC issued a new rule (Order No. 845) concerning revisions to_ the 

interconnection process for large generators which are over 20 MWs. The intent of this rule is to 

reduce the backlog of interconnection queue requests, however, these new regulations put the 

onus on the transmission provider to develop new procedures to accommodate additional 

flexibility for interconnecting generators. The interconnection process is already quite 

complicated with several studies often required to determine the impact of the new generation on 

the transmission grid with various deadlines for each specific step in the process. This was 

manageable when there were only a handful of interconnection requests in a year. However, 

these queues have grown more recently due to the significant increase in the number of smallersized interconnection requests for wind and solar generation. Developers typically put in several 

requests at one time, knowing that many of them will not get built. In some cases, there is more 

proposed generation in the queue than the total customer load in a particular area. 

1. Do you believe that this new interconnection rule will alleviate those backlogs? 

I believe the Commission may have missed an opportunity to better address some of the 

root causes of the ongoing queue backlogs. In my experience, queue backlogs are often 

the result of queues being flooded with speculative projects that may have limited chance 

of being brought to completion. When these speculative projects flow into and out of a 

queue they add frustrating uncertainty for other interconnection customers and the 

transmission providers. The problem can lead to time consuming delays when 

transmission studies need to be recompleted. Yet, as you correctly noted in your 

question, much of the bulk of the regulatory mandates in Order No. 845 fall to the 

transmission providers rather than adopting tools that would more rationally streamline 

the queues to those projects that have the best chance of advancing expeditiously. I am 

concerned that unless the Commission addresses the root causes of the backlogs, 
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especially the problem of so many speculative projects cluttering the queues, the problem 

will persist. 

2. How would modifications made by interconnection customers affect the interconnection 

studies of later-queued requests? 

Your question gets to the heart of the problem of a large unwieldy interconnection queue 

process. As speculative projects drop out of the queue or if they seek to modify their 

project, it can cause a cascade of circumstances that affect other projects in the queue. 

3. Would you agree that vertically-integrated utilities may already be better positioned with 

aggressing grid resilience in transmission planning since generation, transmission and 

distribution needs can be evaluated holistically through the IRP process? 

Undoubtedly, one of the strengths of the vertically integrated utility model is in its ability 

to plan generation, transmission and distribution facilities in a way that ensures public 

imperatives are met in relation to resilience, reliability, affordability and fuel source 

security and diversity. 

The Hon. Scott Peters 

1. As climate change continues and we see more frequent and more intense natural 

disasters destroying our grid, how is the grid affected in terms of capital costs and how 

do those costs affect consumers? 

I have not personally conducted a study of the costs to the grid, and to consumers, related 

to a changing climate. Assessing the costs to individual utilities and their customers 

would likely be specific to each utility given the many differences that each face given 

the geographic diversity of the territories they serve. 
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GREG WALDEN, OREGON 

CHAIRMAN 

Dr. BdwardKrapels 

CEO 

ONE HUNDRED AFTEENTH CONGRESS 

FRANK PALLONE, JR., NEW JERSEY 

RANKING MEMBER 

€onliress of tbt Wnittb ~tatts 

~ou•e of 1\epre•entattue• 

COMMITIEE ON ENERGY AND COMMERCE 

2125 RAvsuRN House OFFICE BuiLPIN<l 

WASHINGTON, DC 20515-6115 Mafority (202) 225-m!? 

Minority {202)22.5-3641 

June 5, 2018 

Anbaric Development Partners 

401 Edgewater Plac:e; Suite 680 

Wakefield, MA 01880 

Dear Dr. Krapels: 

Thank you for appearing before the Subcommittee on Energy on Thursday, May 10, 2018, 

to testify at the hearing entitled "EXlllllinil1g the State of Electric Transmission Infrastructure: 

Investment, Planning, Construction, and Alternatives.» 

Pursuant to the Rules of the Committee on Energy and Commerce, the bearing record 

remains open for ten business days to pennlt Members to submit additional questions for the record, 

which are attached. To facilitate the printing of the hearing record, please respond to these questions 

with a transruittalletter by the close of business on Tuesday, June 19, 2018. Your responses should 

be mailed to Kelly Collins, Legislative Clerk, Committee on Energy and Commerce, 2125 Rayburn 

Hol!Se Office Building, Washington, DC 20515 and e-mailed in Word format to 

Kelly.Colljns@mai!,house.gov. 

Thank you again for your time and effort preparing and delivering testimony before the 

Subcommittee. 

cc: The Honorable Bobby L. Rush, ~-Ranking Member, Subcommittee on Energy 

Attachment 
125 


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Kelly Collins 

Legislative Clerk 

Committee on Energy and Commerce 

2125 Rayburn House Office Building 

Washington, DC 20515 

the future of electricity 

June 18, 2018 

RE: Responses to Additional Questions for the Record, "Examining the State of Electric Transmission 

Infrastructure: Investment, Planning, Construction, and Alternatives" 

Dear Ms. Collins, 

Please find enclosed my responses to the additional questions for the record submitted by Representative 

Upton and Representative Hudson following my testimony before the Subcommittee on Energy on 

Thursday, May 10,2018. 

Hard copies of these responses will be mailed to you via FedEx, and an email copy of these 

responses will be sent to you at Kelly.Collins@mail.house.gov. 

Please be in touch with any further questions. 

Sincerely, 

Edward N. Krapels 

Chief Executive Officer 

Anbaric Development Partners, LLC 

401 Edgewater Place, Suite 680 I Wakefield, MA 01880 I T: 781-683-0711 I info@anbaric.com I anbaric.com 
126 


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the future of electricity 

Question from the Honorable Fred Upton: 

1. You are an infrastructure developer and you've actually built transmission projects, including an 

underwater DC cable connecting New Jersey with Long Island. As you know, DC lines have been around 

ever since Thomas Edison championed the technology. 

a. Can you explain why high-voltage DC transmission lines are not more prevalent in this 

country? 

Answer: The US electric system was built from the inside out: from the cities to the country. As a result, 

electric systems were organized first where there were a lot of consumers and only much later was 

electric service extended out to rural areas. Not accidentally, extension to the countryside required an act 

of congress (The Rural Electrification Act of 1936). It was natural that the incentives of electric 

companies was to economize on the transmission side of the business. Better short distances to consumer 

demand areas than long ones, and AC was cheaper from that perspective than DC, which always needs a 

considerable investment in converter stations (converting from ACto DC on one end, and DC to AC on 

the other end of the transmission line). 

Where electricity had to be transmitted a·very long distance (which only made economic sense if the 

remote generating sources was especially desirable), DC technology received greater consideration. Thus, 

the Pacific Intertie was built in the 1980s to allow California to obtain power from the Columbia River 

hydro system, and the Quebec- New England DC project was built in the 1990s. Also, in the 2000s, a 

series of DC projects (Cross Sound Cable, Neptune and Hudson) were built to connect the downstate New 

York market to New Jersey and Connecticut. 

These projects constitute a tiny fraction of the overall North American transmission system. This stands 

in marked contrast to the American acceptance of the interstate highway system as the lifeblood of 

transportation commerce. The highway system, however, was a creature of the federal government. 

Washington has never placed the same political clout behind the building of an interstate electric 

transmission system. FERC' s efforts to stimulate interregional transmission have largely been 

unsuccessful. 

b. What are the major benefits of DC over AC transmission? 

Answer: Direct current is more controllable than alternating current, and it experiences smaller line losses 

over longer distances. 

2. In a recent article in the Electricity Journal you wrote that interregional coordination almost 

always reaches a dead end because transmission planners only care about the reliability of their own 

systems without having to rely on neighboring regions. 

Answer: Over the last two decades, innovative elective interregional transmission ideas have cropped up 

all over the country in response to the opening of transmission to competition by federal and most state 

regulators, but very few have been built. In the West, several multibillion dollar power lines are under 

development that would connect the resource rich areas of Wyoming, Nevada, and New Mexico to 

California. In New England, new transmission proposals are competing to better the links with Quebec 

and the Maritimes. In the mid-continent, bold transmission initiatives would connect previously 

401 Edgewater Place, Suite 680 I Wakefield, MA 01880 IT: 781-683-07111 info@anbaric.com I anbaric.com 
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the future of electricity 

unconnected states and provinces. In each of these areas, inter-regional electric trade is touted as a 

beneficial result of new infrastructure. After all, transmission is to the power business what the interstate 

highway system is to the broader economy: it is the infrastructure that facilitates trade to the benefit of 

both sides of the line. Those who can make electricity more cheaply can transmit to those where it is more 

costly. Both sides benefit. 

This is why FERC issued "Order I 000" in 20 II, to accelerate the development of interregional 

transmission lines. Seven years later, however, little has been done in pursuit of this laudable objective, 

and this paper will argue that little has been done because FERC was not sufficiently prescriptive in how 

interregional projects should be treated by those who have the power to approve and maintain them at a 

regional and state level. 

The new FERC commissioners appointed by President Donald Trump have a number of opportunities to 

free the development of innovative interregional transmission proposals from regulations that not only 

discourage anyone from proposing new projects, but render existing projects uneconomic. The 

development of new interregional transmission lines should be an important federal policy goal for the 

Trump Administration because it will promote economic growth within the United States. To get that 

growth, FERC needs to develop a more prescriptive policy on how such projects can be originated and 

how their cost should be allocated. 

The primary reason to build interregional transmission lines should be similar to the primary reason to 

build the interstate highway system: as infrastructure that unites the states, and enables economic growth. 

a. If we had this mentality, highways would end at state borders and we would not have an 

interstate highway system. How can we encourage or direct the development of inter-regional 

transmission lines? 

Answer: A key factor allowing the federal government to finance the majority of the cost of the interstate 

highway system was the willingness of President Eisenhower to promote and Congress to support the 

National Interstate and Defense Highways Act of 1956. It provided a new federal gasoline tax that was 

instrumental in the financing of this massive project. In contrast, no President to my knowledge has ever 

supported legislation to create an electric superhighway, nor has Congress initiated and passed such 

legislation. Without a federal push, it is extremely unlikely that the states- who have massively different 

electric market preferences- will provide the energy or the funding to create one. 

Extremely complex and unpredictable interconnection procedures, "mitigation" and regional transmission 

cost allocations imposed on "outside" customers have huge implications for interregional transmission 

projects. If they continue to be applied to new interregional transmission projects, very few will be built 

and some existing projects will become uneconomic. In many parts of America, transmission 

development is already incredibly difficult and demanding. Both existing and new penalties on 

interregional projects make it almost impossible. 

Prevent the damage these regulations wreak starts with FERC. First, FERC should finally follow up on 

the promise made in Order 1000 and create a new category of cost allocation for interregional 

transmission lines. The narrowest version of "beneficiary pays" is simply too restrictive, because it tends 

to rely too heavily on a static analysis of the effects of transmission. In conventional electric power 

market thinking, a powerflow model will show that a new transmission line will raise the price in the 

"source" market and lower it in the "sink" market. But that static picture is never the entire picture. 

401 Edgewater Place, Suite 680 I Wakefield, MA 01880 I T: 781-683-0711 I info@anbaric.com I anbaric.com 
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the future of electricity 

Instead, a transmission line changes the dynamic topography of the region in which it sits: it creates a new 

dynamic that in one year might be to the advantage of the source market, and another year to the sink 

market. The courts have made this more difficult by insisting on extremely narrow "beneficiary pays" 

formulations that, had they applied to interstate highways, the interstate highways system would never 

have been built. 

Second, FERC should direct all ISOs and RTOs to refrain from imposing mitigation rules on interregional 

transmission lines. States have a right, and some would argue the federal government has a responsibility, 

to encourage interregional transmission and thereby enhance competition. The mitigation rules prevent 

that from happening by raising, not lowering, barriers to entry. 

Third, FERC must not allow ISOs and RTOs to impose disproportionately large costs on interregional 

transmission lines. Imposing costs on "foreigners" (THAT IS, American consumers in regions that 

receive power exports) is irresistible. While export customers should pay their fair share of maintaining 

reliability in the regions from which they import electricity, they should not be victims to the kind of 

extremely disproportionate allocations they have suffered in recent PJM procedures. 

The new FERC of the Donald Trump era has an opportunity to dismantle the triple jeopardy. With that, 

not only New York, Connecticut, and New Jersey but also other parts of the country can get on with the 

development one of the critical components of the Administration's infrastructure policy, and make 

electric America great again. 

Question trom the Honorable Richard Hudson: 

On Apri/19, FERC Issued a new rule (Order No. 845) concerning revisions to the Interconnection 

process for large generators which are over 20 MWs. The intent of this rule Is to reduce the backlog of 

Interconnection queue requests, however, these new regulations put the onus on the transmission provider 

to develop new procedures to accommodate additional flexibility for interconnecting generators. The 

Interconnection process is already quite complicated with several studies often required to determine the 

impact of the new generation on the transmission grid with various deadlines for each specific step in the 

process. This was manageable when there were only a handful of interconnection requests in a year. 

However, these queues have grown more recently due to the significant increase In the number of 

smaller-sized Interconnection requests for wind and solar generation. Developers typically put in several 

requests at one time, knowing that many of them will not get built. In some cases, there is more proposed 

generation in the queue than the total customer load in a particular area. 

1. Do you believe that this new interconnection rule will alleviate these backlogs? 

As summarized by the reporters at UtilityDive, "more closely aligning output and nameplate capacity will 

help improve the interconnection process ... [in which] there is also a recurring problem oflate 

interconnection request withdrawals that can lead to interconnection restudies that can increase costs and 

time lines for other participants in the interconnection queue ... Order 845 requires transmission providers 

to allow for provisional interconnection agreements for limited operation of a generating facility prior to 

completion of the full interconnection process. The order also requires transmission providers to create a 

process for interconnection customers to use surplus interconnection service at existing points of 

interconnection." 

401 Edgewater Place, Suite 6801 Wakefield, MA 01880 IT: 781-683-07111 info@anbaric.com I anbaric.com 
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the future of electricity 

These changes are likely to further increase the number of interconnection proposals, and possibly 

contribute to an even greater backlog. In a way, this is good news: it indicates that competition for 

customers is increasing instead of abating, which Congress should welcome. To the extent this increases 

the burden on ISOs and RTOs, it would seem better to give them more resources to handle the demand 

than to choke off the transformation these interconnection requests are ushering in. 

2. How would modifications made by interconnection customers affect the interconnection 

studies of later-queued requests? 

It will increase the complexity of the interconnection process. Again, this is a sign of a vibrant and 

changing market, not a problem to be alleviated by limiting the flexibility of interconnection requests. 

Edward N. Krapels 

Chief Executive Officer 

Anbaric Development Partners, LLC 

401 Edgewater Place, Suite 680 I Wakefield, MA 01880 I T: 781-683-0711 I info@anbaric.com I anbaric.com 
130 


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GREG WALOEN, OREGON 

CHAIRMAN 

ONE HUNDRED FIFTEENTH CONGRESS 

FRANK PALLONE. JR .. NEW JERSEY 

RANKING MEMBER 

QC:ougu~~ of tbt lluittb ~tate~ 

•ou~e of jleprt~entatibt~ 

COMMITTEE ON ENERGY AND COMMERCE 

2125 RAveuRN House OFFICI! ButLOING 

WASHINGTON, DC 20615-6115 

Ms. Jennifer CUrran 

Vice President, System Planning 

Midcontinent ISO 

720 City Center DriVe 

Carmel, IN 46082 

Dear Ms. Curran: 

Mejotlty {202) 225-2927 

Minority (202) lit-3641 

JuneS, 2018 

Thank you for appearing before the Subcommittee on Energy on Thursday, May 10, 2018, 

to testify at the hearing entitled "Examining the State of Electric Transmission Infrastructure: 

Investment, Planning, Construction, and Alternatives." 

Pursuant to the Rules of the Committee on Energy and Commeree, the hearing record 

remains open for ten business days to pennit Members to submit additional questions for the record, 

which are attached. To facilitate the printing of the hearing record, please respond to these questions 

with a transmittal letter by the close of business on Tuesday, June 19, 2018. Your responses should 

be mailed to Kelly Collins, Legislative Clerk, Committee on Energy and Commerce, 2125 Rayburn 

House Office Building, Washington, DC 20515 and e-mailed in Word format to 

K.elly.Collins@mail.house.aov. 

Thank you again for your time and effort preparing and delivering testimony before the 

Subcommittee. 

ee: The Honorshle Bobby L. Rush, Ranking Member, Subcommittee on Energy 

Attachment 
131 


30978.101

Via Overnight and Electronic Delivery 

June 19,2018 

The Honorable Fred Upton, Chairman 

Committee on Energy and Commerce 

Subcommittee on Energy 

2125 Rayburn House Office Building 

Washington, D.C. 20515-6115 

Dear Chairman Upton: 

Jennifer K. Curran 

Vice President, System Planning 

317.249.5258 

jcurran@misoenergy.org 

Thank you for the opportunity to appear before the Subcommittee on Energy on Thursday, May I 0, 2018 to testifY at 

the hearing entitled "Examining the State of Electric Transmission Infrastructure: Investment. Planning. Construction and 

Alternatives." 

Pursuant to your letter of June 5, 2018, containing additional questions for the record submitted by Members 

following the hearing, attached please find my responses to those questions. 

Please do not hesitate to contact me should you have any questions regarding the attached responses to the additional 

questions for the record. You may also contact Kurt Bilas, MISO's executive director of government relations, in our 

Washington, D.C. office, at (202) 309-3550, or kbilas@misoenergy.org. 

Sincerely, 

\\Z\J:>-' (J;N\IJ.V"' \ ·~ 

,j 

Jennifer Curran 

Vice President, System Planning 

Midcontinent ISO 

cc: The Honorable Bobby L. Rush, Raoking Member, Subcommittee on Energy 

Ms. Kelly Collins, Legislative Clerk, Committee on Energy and Commerce 

Attachment: QFR Responses_ 20180510 Energy Subcommittee Hearing_ CUrran.docx 

Midcontinent Independent 

System Operator, Inc. 720 West City Center Or. 2985 Ames Crossing Road 

317.249~5400 Carmel, Indiana 46032 Eagan, Minnesota 55121 

W'WN.misoenerqy.org 

3850 N. Causeway Blvd., 

Two Lakeway, Suite 442 

Metairie, LA 70002 

1700 Centervtew Drive 

Little Rock. AR 72211 
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Jennifer Curran 

Vice President, System Planning 

Midcontinent Independent System Operator, Inc. (MISO) 

Responses to Member's questions for the record for the House Subcommittee on 

Energy's May 10, 2018, hearing entitled "Examining the State of the Electric 

Transmission Infrastructure: Investment, Planning, Construction and Alternatives" 

Questions from the Honorable Fred Upton 

1. FERC Order 1000 requires that certain transmission projects be competitively bid. I 

understand that MISO has opened just two bidding opportunities for projects under 

Order 1000. Other RTOs such as ISO-New England have not offered any opportunities 

for competitive bidding, and your neighbor, SPP, has offered just one, which failed. 

a. Why does it appear that RTOs are not opening up transmission projects for 

competitive bidding? 

MISO's competitive transmission process identifies two project types that are eligible for 

competitive developer selection- Market Efficiency Projects (MEPs) and Multi-Value Projects 

(MVPs). 

Since FERC's acceptance of MISO's competitive transmission process in 2015, MISO has 

approved three MEPs. Two of these were opened for competitive developer selection -the 

Duff-Coleman Project in 2015 and the Huntley-Wilmarth Project in 2016 (which was awarded to 

the incumbent following an applicable state right of first refusal statute). A third MEP, the 

Hartburg-Sabine Junction 500 kV Market Efficiency Project, was identified in 2017 and is 

currently undergoing the selection process. 

Order 1000 focused on reducing barriers to regional projects, which tend to be cyclical in nature. 

To be eligible for competitive selection in MISO's region, transmission projects must meet 

certain criteria, including a benefit-to-cost ratio where benefits are equal to or exceed costs. In 

2011, prior to Order 1000, MISO approved a major set of regional investments- a portfolio of 

seventeen MVPs across its footprint, representing approximately $6 billion in transmission 

system investment. The projects were designed to reduce system congestion and meet 

Renewable Portfolio Standards in several MISO states through 2026. The last project will go 

into service in 2023. 

As the resource portfolio continues to shift, MISO believes that the strength of its planning 

process will continue to identify regional projects that demonstrate value. 

2. We've heard multiple times that Interregional transmission lines simply are not being 

constructed. Can you explain why? 

Order 1000 allows adjacent regions to explore potential solutions that may be more cost 

effective or efficient than regional or local solutions. Interregional projects must show benefit for 

both regions. MISO's experience has shown that most transmission needs can and are being 

addressed by more cost effective and efficient regional or local solutions. 

MISO, which covers an expansive geographic footprint across 15 states and one Canadian 

province, has facilitated nearly $30 billion in total transmission investment, which includes 

interstate transmission, since the first MISO Transmission Expansion Plan in 2003. 

1 
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Interregional planning under Order 1000 is a relatively recent development. While MISO has 

nearly 15 years of regional transmission planning experience, Order 1000 interregional 

compliance filings were made during 2013 and compliance orders were issued through the end 

of 2015. As a result, interregional planning has been slower to evolve as we bridge regional 

differences. Further, the pace of interregional project development, as well as recent larger 

scale regional transmission efforts, has been significantly impacted in recent years by several 

factors, including the need to evolve the metrics used to assess the benefits of transmission to 

reflect changing system conditions. The uncertainty of the future energy landscape and lack of 

clear policy to address that future uncertainty continues to hinder the business case for longlead, large scale transmission projects. 

Transmission investment provides value to the marketplace by opening up opportunities to 

access the most economic resources on the system. That access and ability to maximize the 

benefit of interregional transmission can be hindered by administrative or economic hurdles, 

which in some cases reflect differing operating philosophies and are difficult to overcome. In 

general, it is difficult to achieve alignment and agreement offuture needs, benefits and cost 

allocation across multiple regions that are geographically expansive and contain a diverse 

spectrum of stakeholder opinions. A high level of consensus is critical when moving forward with 

interregional projects. 

Nevertheless, MISO and PJM have made significant progress that our regions can build from. 

We jointly developed and implemented a new transmission concept called Targeted Market 

Efficiency Project (TMEP} upgrades. TMEPs are designed, in the short-term horizon, to address 

historically known market-to-market congestion. MISO and SPP are also working with our joint 

stakeholders on how best to incorporate market-to-market congestion in coordinated 

transmission planning. While these projects are relatively smaller upgrades, they will have a 

large positive benefit to the seam between regions, and we expect them to pave the way for 

future mutually beneficial projects. 

Together with PJM, SPP and our joint stakeholders, we are working to further remove perceived 

barriers to enable the evaluation and potential approval of larger, more cost effective and 

efficient interregional projects and to enhance our processes to find efficiency gains. We 

anticipate adding such enhancements to our Joint Operating Agreements this year. 

3. MISO was very successful with its Multi-Value Project (MVP) effort. Can you explain in 

more detail how the MVP process works and how it's different than the Order 1000 

planning process? 

MISO's planning process included many major elements of FERC Order 1000, even before that 

Order was issued. For example, MISO employed a regional planning process that included 

consideration of public policy needs and had a regional cost allocation mechanism (Multi-Value 

Projects, or MVPs} for those types of projects. MVPs are a category of transmission expansion 

projects that look at portfolios of projects that provide widespread benefits throughout the MISO 

region. MVPs address public policy requirements, reliability and economic benefits. 

In order to be recommended as MVPs, the proposed project portfolio must also meet a series of 

conditions: 

• aligned interests for regional transmission solutions; 

• a robust business case for the projects that evaluates the projects under multiple future 

scenarios; 

2 
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• clearly defined cost allocation methods that closely align who pays with who benefits; 

and 

• cost recovery mechanisms that reduce financial risk. 

All of these items are evaluated through an open and transparent stakeholder review process. 

To provide additional insight and confidence into the planning process, MVPs also undergo 

periodic reevaluation through MVP annual and triannual reviews. 

In 2011, MISO's Board of Directors approved 17 projects, representing approximately $6 billion 

in transmission system investments, as the first MVP portfolio. While the original MVP portfolio 

was developed prior to the implementation of FERC Order 1000, many of the planning reforms 

specified by the Order were already applied to the MVP planning effort. The MVPs were 

demonstrated to have broad regional benefits well in excess of costs, aligned to corresponding 

region-wide cost allocation mechanisms. The portfolio also had widespread support from state 

and regulatory agencies to help meet an important policy need at the time - state Renewable 

Portfolio Standard (RPS) mandates. 

Today, the MVP project category is a part of MISO's Order 1000-compliant regional planning 

process. Projects that qualify as an MVP are regionally cost shared on a load ratio share basis 

(based on energy withdrawals). Because MVPs are regionally cost shared, future MVPs are 

eligible for MlSO's competitive developer selection process. 

a. In terms of allocating the costs of transmission projects, how does MISO seek to 

ensure that beneficiaries pay for transmission? 

MISO employs a suite of mechanisms designed around allocating the costs of transmission 

projects to beneficiaries. 

o Cost allocation for reliability driven projects is focused on the entity that is facing 

a reliability need and is thus benefitting from the project. 

o Cost allocation for projects needed to interconnect new resources is focused on 

those customers seeking to gain access to the MISO transmission system. For 

higher voltage upgrades (defined as those transmission facilities 345kV and up) 

there is a ten percent allocation to all load in MISO in recognition of the broader 

efficiency impacts those facilities provide. 

o Cost allocation for projects to improve market efficiency is based on the 

distribution of calculated benefits for those projects, utilizing multiple quantifiable 

metrics. 

o Cost allocation for portfolios of projects that benefit the MISO region is done on a 

load ratio share basis. These portfolios of projects (MVPs) can be driven by 

public policy needs or a combination of economic and reliability factors. To 

ensure alignment of costs and beneficiaries MISO evaluates MVPs as a part of a 

portfolio of projects that impact the region. 

MISO also regularly reviews cost allocation mechanisms with stakeholders and adjusts the 

methods as necessary for new projects to reflect changing system conditions. The development 

of the Multi-Value Project cost allocation method is an example of the outcome of one such 

stakeholder review. 

Questions from the Honorable Gregg Harper 

3 
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30978.105

1. Under FERC's incentive policy provided certain ROE rate Incentives for transmission 

providers to build projects that either faced unique risks or employed advanced 

technologies. 

a. From your perspective as a grid operator, do these incentives attract needed 

transmission Infrastructure investment? 

Many different factors, including rate incentives, are taken into account by transmission 

providers in making transmission infrastructure investment decisions. As an RTO, MISO's 

planning processes focus on identifying benefits of projects to the system, but we do not build or 

own transmission infrastructure. 

b. In your opinion, would many of these projects still get built without the 

Incentives? 

Because MISO does not build or own transmission lines or recover their costs, it is difficult to 

accurately predict how much impact incentives have on the business decisions of individual 

transmission providers. 

question from the Honorable H. Morgan Griffith 

1. Given the difficulties you mention achieving consensus on who should pay for large 

new transmission investments, would clearer FERC policy on cost allocation address 

another impediment to building the next set of large transmission projects? 

Cost allocation is inherently challenging. However, there are some elements of cost allocation 

where further FERC guidance would be helpful, in particular around which benefits should be 

quantified in the evaluation of regional transmission projects. Transmission, particularly large 

scale Extra-High-Voltage transmission, provides many benefits to multiple parties. It is critical 

that the full scope of benefits are included in the analysis to determine the merits of a project. 

FERC Order 1 000 established that cost allocation should be based on a beneficiary pays 

principle. However, because regional transmission provides multiple types of benefits to multiple 

parties, to allocate to beneficiaries you must first identify who is benefitting and why. Some 

benefit metrics, such as Adjusted Production Cost savings, are widely utilized and understood 

throughout the industry. Other metrics based on new technologies or initiatives are more difficult 

to quantify and gain acceptance. For example, there is an increased focus in the industry 

around system resilience but, to date, there is no widely accepted method to quantify the 

economic benefit of regional transmission investment to overall system resilience. FERC or 

industry efforts to define and quantify an economic metric associated with improved system 

resilience could help integrate those elements into regional planning processes. 

questions from the Honorable Richard Hudson 

On Apri119, FERC Issued a new rule (Order No. 845) concerning revisions to the 

interconnection process for large generators which are over 20 MWs. The intent of this 

rule is to reduce the backlog of Interconnection queue requests, however, these new 

regulations put the onus on the transmission provider to develop new procedures to 

accommodate additional flexibility for Interconnecting generators. The interconnection 

process is already quite complicated with several studies often required to determine the 

impact of the new generation on the transmission grid with various deadlines for each 

specific step in the process. This was manageable when there were only a handful of 

interconnection requests per year. However, these queues have grown more recently due 

to the significant increase in the number of smaller-sized interconnection requests for 

4 
136 


30978.106

wind and solar generation. Developers typically put in several requests at one time, 

knowing that many of them will not get built. In some cases, there Is more proposed 

generation in the queue than the total customer load in a particular area. 

1. Do you believe that this new Interconnection rule will alleviate these backlogs? 

While FERC's recent rule on generation interconnection procedures is an important step toward 

expediting interconnection queue processing, it will not be sufficient to alleviate MISO's current 

backlogs. 

Prior to the issuance of Order 845 MISO had already instituted many of its provisions, and we 

continue to seek opportunities to improve our processes. Some of the challenges we face 

include queue size and related process delays due to interconnection study complexity. MISO 

currently has over 90,000 MW of requests in our generator interconnection queue. This is over 

half of MISO's current total installed generation capacity of 175,000 MW. 

Historical experience and discussions with customers suggests many of the projects in the 

queue will not be built. The sheer size of the existing queue creates challenges that are 

preventing those projects that are ready and prepared for commercial operation from getting 

their Generation Interconnection Agreements in a timely manner. 

MISO continues to work with stakeholders to develop reforms to help expedite the process and 

move projects through the queue more quickly. The near term focus includes changes to site 

control requirements and system study processes, and modifications to generation study 

models. 

2. How would modifications made by interconnection customers affect the 

interconnection studies of later-queued requests? 

MISO's process is designed to ensure that modifications do not adversely affect the results of 

later-queued requests. Any request for modifications must be evaluated by MISO to determine 

the potential impact on later-queued project requests. If the requested modification is 

determined to impact the cost or time, including study time, for a lower queued project, then 

MISO will deny the modification request or require the interconnection request to re-enter the 

queue. 

Question from the Honorable Tim Walberg 

1. You note that FERC Order 1000 and the advent of competitive bidding is one of the 

items that has increased the complexity of developing additional large scale 

investment plans. Can changes to this policy remove some of the challenges to 

developing the next set of regional transmission investments needed in MISO? 

Refinement of Order 1 000 would reduce the complexity of and potentially improve the 

collaboration around development of transmission investments in MISO's region. Key to the 

refinement is that FERC establish a clear, holistic view of the objectives and success measures 

for transmission investment. MISO's focus, first and foremost, is ensuring that necessary 

regional and interregional transmission -the most efficient plans to provide benefits to 

customers in excess of costs- is developed in the region. Metrics that reflect those objectives, 

rather than simply counting the number of projects in a specific category, would be welcomed. 

5 
137 


30978.107

GREG WAlDEN, OREGON 

CHAIRMAN 

Dr. Ralph lzzo 

ONE HUNDRED FIFTEENTH CONGRESS 

FRANK PALLONE, JR .. NEW JERSEY 

RANKING MEMBER 

ftongrt~~ of tbt llntttb 6tatt~ 

A>o~t of !Uprtltntattbel 

COMMITTEE ON ENERGY AND COMMERCE 

2125 RAvsuRN HouS!! 0FACE BuiLDING 

WASHINGTON, DC 2051!Hl115 Majority f-201) 2254927 

Minority {202l .225-3641 

June5,2018 

Chairman, President, and CEO 

Public Service Enterprise Group Incorporated 

80 Park Plaza 

Newark, NJ 07101 

Dear Dr. Izzo: 

Thank you for appearing before the Subcommittee on Energy on Thursday, May I 0, 2018, 

to testify at the hearing entitled "Examining the State of Electric Transmission Infrastructure: 

Investment, Planning, Construction, and Alternatives.~ 

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. To facilitate the pricting of the hearing record, please respond to these questions 

with a transmittal letter by the close of business on Tuesday, June 19, 2018. Your responses should 

be mailed to Kelly Collins, Legislative Clerk, Committee on Energy and Commerce, 2125 Rayburn 

House Office Building, Washington, DC 20515 and e·mailed in Word format to 

Kelly.Co!lins@majl.house.gov. 

Thank you again for your time and effort preparing and delivering testimony before the 

Subcommittee. 

cc: The Honorable Bobby L. Rush, Ranking Member, Subcommittee on Energy 

Attachment 
138 


30978.108

Ralph lzzo, Public Service Enterprise Group 

Additional Questions for the Record 

"Examining Transmission Infrastructure: Investment. Planning, Construction and Alternatives" 

House Energy and Commerce Subcommittee on Energy 

May10,2018 

The Honorable Fred Upton 

1. PSEG opposed Order 1000 from the start when it was initially proposed in 2010. Setting aside 

the concerns you have with the transmission planning process, do you believe that there 

should be competition among incumbent utilities like PSEG and new transmission developers? 

If no, why not? 

A: As a general principle, competition in any sector tends to drive down costs and spur 

innovation, both of which can benefit consumers. But competition is only an economic 

principle. Without the right rules driving to the right outcomes, consumers can still be 

on the losing end. 

When it comes to implementation of Order 1000 in PJM, neither the rules nor the 

resulting outcomes are in the customer's long-term interest. If I held a competition to 

build a car but didn't specify whether I wanted a Rolls Royce or a Yugo or a school bus, 

competitors would spend a lot of money trying to guess what I wanted, and I'd be 

stumped as to how to fairly evaluate the merits of such wildly different solutions. 

Moreover, if my only objective were to minimize my up-front cash outlay, solutions that 

provide longer term value, durability, or greater optionality at a higher initial cost would 

not even make the cut. 

Keeping initial costs low for consumers is an important objective, but it needs to be 

balanced against other important outcomes such as grid resilience, adaptability and 

reliability over the long-term. If band aid solutions for grid upgrades become the default 

choice, customers will surely face higher costs over the longer term. 

Order 1000 implementation is not living up to the ideals of a competitive, efficient 

process. In PJM we have seen significant confusion and chaos erupt as the RTO grapples 

with apples-to-oranges cost comparisons and how to interpret developer cost cap 

commitments. We've seen the RTO reach beyond its expertise to try to assess which 

projects can get environmental permits, and try to mediate thorny political disputes 

between states. At a more basic level, there is an unsettling lack of clarity over which 

entity will be accountable for the ongoing hands-on management of the contract with a 

chosen developer to execute a project. Is it the RTO? Is it FERC? As anyone who has 
139 


30978.109

undertaken a home renovation can tell you, this is not something that can be left on 

auto pilot. 

2. In your written testimony, you provided a number of bullets highlighting some disappointing 

facts. Notably, not one of the non-RTO planning regions have provided even a single 

competitive transmission bidding opportunity, and that in the RTO regions there have just 

beeen a handful of bidding opportunities. 

a. While I recognize that you are advocating for the outright repeal of Order 1000, do 

you believe that there is any way to salvage FERC's competitive transmission 

development objective? 

A: PSEG recommends that the FERC pause implementation of Order 1000 until planning 

regions affirmatively demonstrate that the Order is providing value and not costing 

consumers more. Planning regions should also demonstrate that they have the processes 

and controls in place to successfully administer competitive bids and then oversee a 

developer's commitment to build. For instance, if a developer agrees to cap their 

construction costs, this can save consumers money, but only if the developer is held to 

these commitments. As the RTOs themselves have conceded, they are not prepared or 

resourced for this important ongoing oversight role. 

Finally, to return to the car analogy, the Order 1000 process in PJM has been plagued by 

too many variables. Far from spurring innovation, this approach has tended to create 

paralysis. The collaboration that used to occur among grid planners and transmission 

owners across the region to design the best solution has been lost. Even if the rules can be 

ironed out, it may be best to narrow the application of Order 1000 to those projects that 

can bring economic value to consumers, and not apply it to critical reliability upgrades 

needed to maintain the grid. 

3. We've heard some concerns that large investor-owned utilities (IOUs) may prefer to Invest in 

capital-Intensive transmission projects to Increase their rate base Instead of selecting lessexpensive projects that can achieve the same effect at a lower cost to consumers. 

a. Do we have regulatory policies in place that create an incentive to spend more simply 

to Increase utility's rate base? 

A: Utilities like PSE&G are obligated under state law to provide safe and reliable service 

to customers. Our state officials and our customers expect us to keep the lights on and, 

if there is a problem, we are the first to receive a phone call. Thus, our focus and our 

priority at all times is on reliability of the system and making the necessary investments 

to ensure long-term reliability. Over the last 10 years, our investment in the 
140 


30978.110

transmission grid has resulted in a five-fold decrease in transmission outages on our 

system. 

At the same time, we are required to identify cost-effective solutions, and there are 

several layers of review to ensure the investments are both necessary and prudent. 

First, our proposed transmission projects are reviewed extensively for cost-effectiveness 

and need by the independent grid operator and by other key stakeholders in the 

planning process before they ever get the green light. Second, when we site a project 

during the construction phase, our state commission or the impacted towns are 

required to review the project for cost effectiveness, need and availability of 

alternatives. Finally, as a rate-regulated company, all transmission projects are subject 

to the oversight of FERC, which has the authority to review our project costs and our 

rates to ensure they are just and reasonable and that our expenditures are prudent. 

The Honorable Gregg Harper 

1. As you know, FERC has effectively lacked a return-on-equity (ROE) policy ever since the D.C. 

Circuit struck down Its policy (i.e., Opinion No. 531) more than a year ago. In the absence of a 

clear and stable ratemaking policy, how are transmission owners and developers responding 

to this uncertainty? As a CEO of a major utility with transmission projects, what is your 

perspective on this matter? 

A: In order to build, own, and operate adequate transmission infrastructure that 

ensures reliable and affordable service to customers, transmission owners and 

developers require that FERC establish a clear and consistent ratemaking policy. 

Because transmission infrastructure involves a long-term commitment, often 40 years or 

more, investors require adequate and stable returns over the long-term to provide 

financing for resilient and sound infrastructure development. As the Commission 

considers its ROE policy, it must examine whether its methodology is sufficient to attract 

the capital necessary to meet transmission investment needs at a time when the 

transmission system needs to replace aging infrastructure, enhance resilience and 

accommodate a changing generation resource pQrtfolio. 

The Honorable Richard Hudson 

On April19, FERC Issued a new rule (Order No. 845) concerning revisions to the 

Interconnection process for large generators which are over 20 MWs. The intent of this rule Is 

to reduce backlog of interconnection queue requests, however, these new regulations put the 

onus on the transmission provider to develop new procedures to accommodate additional 

flexibility for interconnecting generators. The interconnection process Is already quite 

complicated with several studies often required to determine the impact of the new 

generation on the transmission grid with various deadlines for each specific step In the 

process. This was manageable when there were only a handful of Interconnection requests in 

a year. However, these queues have grown more recently due to significant Increase in the 
141 


30978.111

number of smaller-sized interconnection requests for wind and solar generation. Developers 

typically put In several requests at one time, knowing that many of them will not get built. In 

some cases, there is more proposed generation In the queue than the total customer load in a 

particular area. 

1. Do you believe that this new interconnection rule will alleviate these backlogs? 

2. How would modifications made by interconnection customers affect the 

Interconnection studies of later-queued requests? 

A: Through Order 845, FERC has implemented significant reforms that should 

help to mitigate some of the backlogs in the interconnection queue. However, 

it is unlikely that these reforms will completely alleviate backlogs, in part 

because developers want and need flexibility (and therefore put in multiple 

requests and/or change their queue requests) and in part because the RTOs are 

trying to ensure that generators pay their appropriate share of costs rather than 

having these costs shifted to customers. PJM has actually made significant 

progress in clearing up the queue backlog over the last several years, and the 

FERC order should continue to help. 
142 


30978.112

GREG WALDEN, OREGON 

CHAIRMAN 

Mr. John Twitty 

Executive Director 

ONE HUNDRED FIFTEENTH CONGRESS 

FRANK PALLONE, JR., NEW JERSEY 

RANKING MEMSER 

fl:ongrt~~ of tbt tlnttdt li>ta:tt~ 

•ou~e of 1\epre"entatib~ 

COMMITTEE ON ENERGY AND COMMERCE 

2125 RAvsuRN House Omce BuiLDING 

WASHINGTON, DC 20515--6115 Majority (B) 226-m'l 

Minol'itv ~) 2.25-3641 

June5,2018 

Tnmsmission Access Policy Study Group 

P.O. Box 14364 

Springfield, MO 65814 

Dear Mr. Twitty: 

Thank you for appearing before the Subcommittee on Energy on Thursday, May 10,2018, 

to testify at the hearing entitled "Examining the State of Electric Transmission Infrastructore: 

Investment, Planning, Construction, and Alternatives." 

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. To facilitate the printing of the hearing record, plesse tespond to these questions 

with a transmittal letter by lhe close ofbusiness on Tuesday, June 19,2018. Your responses should 

be mailed to Kelly Collins, Legislative Clerk, Committee on Energy and Commerce, 2125 Rayburn 

House Office Building, Washington, DC 20515 and e-mailed in Word format to 

Kelly.Collins@mail.house.gov. 

Thank you again for your time and effort preparing and delivering testimony before the 

Subcommittee. 

cc: Tbe Honorable Bobby L. Rush, Ranking Member, Subcommittee on Energy 

Attachment 
143 


30978.113

TAPS Representing community and customer-owned utilities. 

Advancing electric transmission, reliability and market 

issues before FERC, NERC and Congress. 

Chairman Fred Upton 

Subcommittee on Energy 

Committee on Energy and Commerce 

2125 Rayburn House Office Building 

Washington, DC 20515 

VIA ELECTRONIC DELIVERY 

Dear Subcommittee Chairman Upton, 

June 19, 2018 

It was a pleasure to testify before the Energy Subcommittee on Thursday, May 10, 2018, at the 

hearing entitled "Examining the State of Electric Transmission Infrastructure: Investment, 

Planning, Construction and Alternatives" 

In response to your request dated June S, 2018, for additional information for the record, I 

respectfully submit the attached response to the questions posed by you and other members of 

the Committee. 

Thank you for your continued interest in the electric markets and the work the subcommittee is 

undertaking in the Powering America series. The electric sector is undergoing a period of 

significant change and Congressional oversight is appropriate at this time. 

Sincerely, 

John Twitty 

Attachment: "TAPS Response to House E and C QFR" 
144 


30978.114

Responses to Additional Questions for the Record 

The Honorable Fred Upton 

1. In 2012, the Commission issued a policy statement encouraging transmission developers 

seeking rate incentives to participate in joint ownership arrangements (JOAs). FERC 

found that such arrangements can be beneficial by diversifying financial risk across 

multiple owners and minimizing siting risks. From your perspective have transmission 

developers been willing to partner with your utilities [as encouraged by] FERC's policy 

statement in 2012? 

Response: 

Although the Commission's 2012 Incentive Policy Statement correctly recognized the benefits of 

joint ownership arrangements and sought to encourage them, this encouragement has proven 

insufficient to induce large transmission owners and other developers to enable small embedded 

load-serving entities to invest in their share of the grid. As a result, the answer to your question 

is generally no-developers have generally been unwilling to partner with transmissiondependent load-serving entities. Incumbent utilities have been even less willing to do so. 

GridLiance, a non-incumbent transmission developer focused on partnering with public power 

entities and cooperatives, 1 is a limited exception to that general statement. However, although a 

number of Transmission Access Policy Study Group ("TAPS") members have engaged with 

GridLiance in proposing projects, there has been little tangible progress. In part that has been 

due to the failings of the Order I 000 planning process, as currently implemented. FERC Staffs 

own analysis shows that in 2016, no proposals submitted by nonincumbent transmission 

developers were selected by any of the transmission planning regions that had competitive 

proposal windows2

-a strong indication that the Commission's effort to foster more efficient and 

cost-effective transmission development through competition is significantly flawed. 

2. Your testimony suggested that FERC must do more to make sure that grid planning 

encompasses all entities that use the grid for delivery of electric energy to consumers. 

What suggestions would you have for Congress to encourage FERC to assure that 

planning is more inclusive? 

Response: 

Congress should exercise oversight authority to inform FERC that this is a priority for the 

Committee, and urge FERC to do more to encourage joint ownership arrangements. There is 

much that FERC can do to achieve this important objective. 

1 http://www.gridliance.com/. 

2 FERC, 2017 Transmission Metrics Staff Report at 4 (2017), available at https://www.ferc.gov/legal!staffreoorts/2017/transmission-investment-metrics.pdf. 
145 


30978.115

For example, FERC can use its authority under Section 219 of the Federal Power Act ("FPA"), 

which provides for incentive-based transmission rates, to more directly link incentives to 

willingness to enter into joint ownership arrangements. Specifically, those seeking transmission 

rate incentives, particularly incentive equity returns, should not be permitted to turn away loadserving entities in the footprint seeking to make their load-ratio investment in the grid. Instead, a 

showing that the applicant has offered such investment opportunities on reasonable terms should 

be a prerequisite for incentives. Similarly, Congress could urge FERC to also explore using its 

other authority to encourage joint transmission ownership. For example, the willingness to offer 

load-serving entities in the footprint an opportunity to make their load-ratio investment in the 

grid on reasonable terms could be a consideration when evaluating whether a proposed merger is 

in the public interest. 

In addition, FERC's Order I 000 transmission planning process can be a more effective vehicle 

for fostering inclusive transmission investments. As described in my May 10,2018 written 

testimony at pages 5-6, Order 1000 also recognized the value of and encouraged joint ownership 

arrangements, but more can be done to achieve that objective. Non-incumbent transmission 

developers, especially those (like GridLiance) that accommodate participation by small loadserving entities, should have a fair opportunity to compete to develop needed new transmission. 

Indeed, a developer's inclusiveness of small load-serving entities would merit positive 

consideration in the selection process. Unfortunately, despite Order 1000's efforts to promote a 

competitive transmission development process and vigorous competition for those projects that 

have been open to competition, positive results have been limited, as FERC's own analysis 

confirms (as noted above). As discussed on pages 13-14 of my written testimony, Congress 

should encourage the Commission to revisit and reinvigorate the Order 1000 competitive 

transmission development process in a manner that will promote joint transmission ownership, as 

well as use competitive discipline to curb rising transmission costs. 

FERC's exercise of the full range of its FPA authority to promote joint ownership, as urged 

above, would fulfill Congress' directive in FP A Section 217 by enabling load-serving entities to 

directly participate in ensuring that their reasonable needs are satisfied, and would allow them to 

offset the increasing cost of transmission, benefiting consumers and businesses. 

3. In the Powering America hearing series, the Committee has heard concerns that the 

RTOs may not be functioning as originally intended. Your members have assets and 

serve customers in virtually all of the RTOs. Can you tell me the biggest problems your 

members face in the RTOs and what can be done to better address the concerns? 

Response: 

As you correctly note, TAPS members serve customers in virtually all the RTOs. In fact, even 

though they are relatively small, a number ofT APS members have loads and diverse resources in 

multiple RTOs due to the RTO-membership decisions of large transmission owners. Large 

transmission owner changes in their RTO membership can significantly impact the ability of our 

members to continue to use their long-term resources to serve their loads. As discussed in my 

written testimony at pages 10-11, such changes can create an RTO seam that disrupts the longterm power supply arrangements of embedded load-serving entities that have loads and/or 

resources on the larger transmission owners, significantly increasing the costs and risks to which 

2 
146 


30978.116

the smaller utility and its customers are exposed. Nevertheless, FERC generally offers little or 

no protection to such embedded utilities when such RTO membership changes occur. Indeed, 

rather than fulfill its FPA Section 217 obligations to preserve and honor the load-serving entity's 

long-term rights to firm delivery of its capacity resources to it load, the Commission has 

accepted new RTO resource adequacy requirements that aggravate the adverse impacts. 

Capacity markets are a significant concern to TAPS members. TAPS members in the eastern 

RTO face mandatory capacity "markets," which are administrative constructs that include 

features that undermine the members' traditional, obligation-to-serve business model. For 

example, the ISO New England and PJM tariffs include minimum offer pricing rules 

("MOPRs"). TAPS members in those regions undertake long-term power supply commitments 

to fulfill their load-serving resource adequacy obligations. Under the MOPRs, however, they 

may have to purchase capacity a second time if the minimum offer price imputed by the RTO to 

those long-term capacity resources causes them not to clear in the capacity "market." 

Continuously changing rules and performance requirements also can disqualify their long-term 

resources from being counted for resource adequacy. Such restrictions undermine the ability of 

public power entities to make the long-term power supply commitments that Congress sought to 

protect through FPA Section 217, and which have a proven track record of supporting reliability, 

adequacy, and resilience. Nevertheless, in a recent decision, a divided FERC indicated 

receptivity to expanding MOPRs.3 

So far, FERC has rejected efforts by Midcontinent Independent System Operator ("MISO") and 

certain generators to import aspects of the mandatory eastern market capacity constructs into the 

MISO region, in which more than 90% of the load is subject to traditional state cost-of-service 

regulation. However, various generators continue to press for such changes in order to increase 

prices. Costs to consumers are also threatened by the Commission's refusal to apply FP A 

Section 217's directives to ensure delivery of the capacity associated with load-serving entity's 

power supply arrangements, as I explain at pages 9-10 of my written testimony. 

As my comments above highlight, minimizing cost to American consumers and businesses, who 

rely on electricity for economic and social well-being, is not the central focus ofRTOs. Indeed, 

nearly a decade ago, FERC declined to mandate specific statements in RTO mission statements 

requiring RTOs to provide cost reductions and net benefits to the ultimate consumers they serve, 

and rejected other proposals to make RTOs more accountable.4 Particularly given the recent 

GAO findings that FERC lacks the data to assess RTO performance,5 Congress should exercise 

oversight to ensure that the FP A's overarching consumer protection mandate is not forgotten. 6 

3 ISO New England, Inc., 162 FERC, 61,205 (2018), reh'gpending. 

4 Wholesale Competition in Regions with Organized Electric Markets, Order No. 719-A, 74 Fed. Reg. 37,776, 

37,799, 37,801 (July 29, 2009), FERC Stats. & Regs., 31,292, PP 178-180, 193, reh'g on other points, 

Order No. 719-B, 129 FERC, 61,252 (2009). 

5 Electricity Markets: Four Regions Use Capacity Markets to Help Ensure Adequate Resources, but FERC Has Not 

Fully Assessed Their Performance, U.S. General Accounting Office (Dec. 7, 2017), 

https://www.gao.gov/products/GA0-!8-131 ?utm medium=email&utm source=govdelivezy. 

6 See, e.g., FERCv. EPSA, 136 S. Ct. 760, 781-82 (2016) (finding FERC has statutory duty to hold down prices and 

the FPA "aims to protect 'against excessive prices"'); At/. Ref Co. v. Pub. Serv. Comm'n of NY., 360 U.S. 378, 388 

3 
147 


30978.117

The Honorable H. Morgan Griffith 

l. You stated in your testimony that the Joint Ownership transmission model has many 

benefits. What are some of the benefits over our current model and what steps can we do 

to increase joint ownership opportunities for transmission? 

Response: 

The joint ownership model provides numerous benefits. They include the following: 

1. Inclusive joint ownership makes joint planning real. Although FERC has issued rules to 

promote open, inclusive, and transparent planning they have fallen short of accomplishing 

the goals. There is a big practical difference in how planning is accomplished when all loadserving entities are at the table as owners. Aligning the ownership structure of the grid with 

the reality of the way the network operates results in better planning. When diverse parties 

are owners, openness, transparency, and more balanced decision making flow automatically. 

The end result is more efficient grid investment and a more robust and resilient grid. 

2. Inclusive joint ownership results in a better and more efficient transmission system planned 

to meet multiple needs. This has been the experience of TAPS members in Wisconsin, where 

combining five systems into one jointly owned transco (the American Transmission 

Company or "ATC") has certainly led to a more rationally developed system than had 

balkanized planning and construction.7 We also see it in CapX2020, a joint initiative of 11 

transmission-owning utilities in Minnesota, North Dakota, South Dakota, and Wisconsin 

formed to upgrade and expand the electric transmission grid to ensure continued reliable and 

affordable service. The 800 mile, nearly $2 billion investment includes four 345-kilovolt 

transmission lines and a 230-kilovolt line. It is the largest development of new transmission 

in the upper Midwest in 40 years.8 

3. The diverse support that joint ownership provides is very important in siting. By meeting the 

needs of multiple utilities, a joint project is able to demonstrate multiple benefits. Although 

participation by municipals and cooperatives may be relatively small percentage-wise, these 

utilities bring a wealth of political support to the state approval process. This support can 

make all the difference in speeding up permitting and addressing local concerns. FERC 

explicitly recognized this benefit in its 2012 Incentive Policy Statement. 

4. Inclusive joint ownership arrangements provide the critical alignment of interests that makes 

it easier for state regulators to approve proposed transmission projects. When state 

commissions are presented with projects that are least-cost because they meet multiple needs, 

when they see unity among the utilities on need, and when they are faced with a broad base 

(1959) (requiring natural gas be sold "at tbe lowest possible reasonable rate consistent with the maintenance of 

adequate service in tbe public interest"). 

1 https://www.atcllc.com/. 

8 http://www.capx2020.com/. 

4 
148 


30978.118

of support from diverse stakeholders, it is far easier for them to grant requested 

authorizations. 

5. Inclusive joint ownership makes the cost allocation issue easier to resolve, although it still 

remains a thorny issue. For instance, while ATC's transmission rates have been increasing 

because of ATC's construction efforts, municipal and cooperative owners, through their 

ownership in ATC, have been able to offset about 20% of those costs. This has made it 

easier for them to support needed ATC build-out. Similarly, investor-owned utilities that are 

able to participate in projects have an earnings opportunity, rather than simply an opportunity 

to pay. 

6. Inclusive joint ownership spreads the risk of major projects broadly and provides a variety of 

sources of capital for projects. In a post-financial crisis world of tightened credit and 

tougher credit-worthiness standards, the financial diversity and strength achieved through 

joint ownership arrangements should be increasingly valuable. FERC explicitly recognized 

this advantage of joint transmission ownership as a risk reducing in its 2012 Incentive Policy 

Statement. 

7. The broad base of support achieved through joint ownership arrangements can be essential 

to securing state legislative action required to better align retail rate recovery with the need 

for supporting major transmission investment, as has occurred in Minnesota with the full 

support of the CapX group. 

8. Inclusive joint ownership arrangements reduce the need for FERC to referee rate and other 

disputes. 

9. Inclusive joint ownership arrangements benefit consumers. The benefits listed above work 

together to produce transmission better designed to meet all needs, and that can be sited and 

built more quickly. As a result, inclusive joint ownership arrangements benefit consumers 

and reduce costs. 

As to what steps that can be taken to increase joint ownership, step one would be to exercise 

oversight authority to inform FERC that this is a priority for the Committee, and urge FERC to 

do more to encourage joint ownership arrangements. There is much that FERC can do to 

achieve this important objective. Please see my response to the second question from Chairman 

Upton. 

2. How will we know when we've achieved a cost-effective, appropriate level of resilience? 

a. Do you think we have the data in place to measure resilience currently? 

Response: 

5 
149 


30978.119

In comments filed with FERC in its ongoing Grid Resilience proceeding,9 TAPS urged against a 

one-size-fits-all approach to identifying and addressing resilience challenges. Each region faces 

different resilience challenges, based on its particular resource and load mix, location, scope, 

market design, the retail regulatory systems of the states in its footprint, and regional differences 

in the pace and direction of the changes transforming the electric industry. Establishing 

priorities and metrics-a crucial first step toward any resilience program-will also require local 

knowledge and assessment of the costs and benefits of potential actions to improve resilience. 

The key question as to the level of resilience to be achieved can best be answered by balancing 

the interests of multiple stakeholder groups, with particular attention to state and local regulators, 

consistent with FPA Section 217(b)(4)'s directive to the Commission to facilitate planning for 

the reasonable needs of load-serving entities. TAPS urged FERC to allow RTO stakeholder 

processes time to build consensus on these complex issues. 

As noted, the crucial question is: ''what is resilient enough?" "Resilience" should not become a 

license for RTOs to gold-plate the system by taking unilateral actions that unduly drive up the 

costs to consumers, including transmission costs-an outcome fundamentally inconsistent with 

FP A Section 217(b )( 4)' s directive to the Commission to facilitate planning for the reasonable 

needs of load-serving entities. It is always possible to build more redundancy into the grid or 

require ever higher levels of reserves, spare equipment, and personnel standing by. Therefore, to 

make "resilience" a useful and meaningful concept for evaluating and planning the grid, we have 

to decide: What are the scenarios that we want the system to be able to withstand? What are the 

specific restoration targets that we want to achieve? And at what cost? 

The North American Electric Reliability Corporation's ("NERC") definition10 of"Adequate 

Level of Reliability" 11 is instructive: it distinguishes (at 1) between predetermined Disturbances 

("the more probable Disturbances to which the power system is planned, designed, and 

operated") and "low probability Disturbances," and recognizes that it may be appropriate to treat 

them differently. NERC states (at 4) that 

[Bulk Electric System ("BES")] owners and operators may not be able 

to apply any economically justifiable or practical measures to prevent 

or mitigate [the] Adverse Reliability Impact on theBES [oflow 

probability Disturbances], despite the fact that these events can result 

in Cascading, uncontrolled separation or voltage collapse. For this 

reason, these events generally fall outside of the design and operating 

criteria for BES owners and operators. 

9 See Comments of Transmission Access Policy Study Group, Docket No. AD 18-7-000 (May 9, 20 18), available at 

https://elibrary.ferc.gov/idmws/commoniopennat.asp?fileiD=l4913057. 

10 N. Am. Elec. Reliability Corp., Informational Filing on the Definition of"Adequate Level of Reliability," Docket 

No. RR06-1-000 (May 10, 2013), available at 

https://elibrary.ferc.gov/idmws/commonlopennat.asp?fileiD=l3257018. 

'' A criterion for being certified by FERC as the Electric Reliability Organization is "the ability to develop 

and enforce ... reliability standards that provide for an adequate level of reliability of the bulk-power system." 

FPA § 215(c)(l), 16 U.S.C. § 824o(c)(l). 

6 
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NERC's "Adequate Level of Reliability" definition thus recognizes (as Congress implicitly did 

by including the word "adequate" in the statute) that a requirement of "zero blackouts" is neither 

economically justifiable nor practically feasible. 

Decisions about the degree of resilience and regional priorities necessarily entail judgments as to 

the risks and costs that consumers should bear. There must also be a requirement that the 

benefits of resilience measures outweigh their costs. Implementing this standard will not be 

easy: assessing the risks and benefits associated with mitigating high impact/low frequency 

events is difficult, particularly where investments may rapidly become obsolete as the electric 

industry continues to rapidly evolve. Moreover, they will have ramifications for matters outside 

the Commission's jurisdiction (e.g., retail service reliability and local distribution facilities); and 

the strategies available to achieve resilience may well require close collaboration with 

distribution utilities and relevant electric retail regulatory authorities. For these reasons, TAPS 

urged that determinations as to resilience priorities and measures should be addressed on a 

regional basis through the stakeholder process, with appropriate deference to state and local 

regulators. Moreover, the decision-making process to undertake resilience measures must be 

transparent, and the measures must be just, reasonable, not unduly discriminatory, cost-effective, 

and subject to FERC approval. 

The Honorable Richard Hudson 

On April 19, FERC issued a new rule (Order No. 845) concerning revisions to the 

interconnection process for large generators which are over 20 MWs. The intent of this rule is to 

reduce the backlog of interconnection queue requests, however, these new regulations put the 

onus on the transmission provider to develop new procedures to accommodate additional 

flexibility for interconnecting generators. The interconnection process is already quite 

complicated with several studies often required to determine the impact of the new generation on 

the transmission grid with various deadlines for each specific step in the process. This was 

manageable when there were only a handful of interconnection requests in a year. However, 

these queues have grown more recently due to the significant increase in the number of smallersized interconnection requests for wind and solar generation. Developers typically put in several 

requests at one time, knowing that many of them will not get built. In some cases, there is more 

proposed generation in the queue than the total customer load in a particular area. 

1. Do you believe that this new interconnection rule will alleviate these backlogs? 

2. How would modifications made by interconnection customers affect the interconnection 

studies of later-queued requests? 

Response: 

TAPS recognizes the challenges associated with the interconnection queue and backlogs. TAPS 

filed comments in the rulemaking proceeding leading up to Order 845 that generally supported 

the proposed reforms, which were drawn from lessons learned in RTO areas and reasonably 

balance the needs of interconnection customers with the needs of load and transmission 

7 
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30978.121

providers. 12 While TAPS is hopeful that the reforms will be helpful, we are unable to assess the 

specific impacts about which the questions inquire. 

June 19,2018 

12 Comments of Transmission Access Policy Study Group, Docket No. RM17-8-000 (Apr. 13, 2017), available at 

https://elibrarv.ferc.gov/idmws/common!OoenNat.asp?fileiD=l4558960. 

8 
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30978.122

GREG WALDEN, OREGON 

CHAIRMAN 

ONE HUNDRED FIFTEENTH CONGRESS 

FRANK PALLONE, JR., NEW JERSEY 

RANKING MEMBER 

€ongrt5~ of tbt Wntttb 6tatt~ 

•ouse of l\epusentatibes 

COMMITTEE ON ENERGY AND COMMERCE 

2125 RAYBURN House OFFICE BUilDING 

WASHINGTON, DC 20515-6115 

Mr. Rob Gramlich 

Founder and President 

Grid Strategies LLC 

9207 Klrkdale Road 

Bethesda, MD 20817 

Dear Mr. Gramlich: 

Major!tv {2021225-2927 

Mlnorlly !20212254641 

JuneS, 2018 

Thank you for appearing before the Subcommittee on Energy on Thursday, May I 0, 2018, 

to testify at the hearing entitled "Examining the State ofEJectric Transmission Inftastructure: 

Investment, Planning, Construction, and Alternatives." 

Pursuant to the Rules of the Committee on Energy and Commerce, the henring record 

remains open for ten business days to permit Members to submit additional questions for the record, 

which are attached. To facilitate the printing of the bearing record, please respond to these questions 

with a transmittslletter by the close of business on Tuesday, June 19, 2018. Your respnnses should 

be mailed to Kelly Collins, Legislative Clerk, Committee on Energy and Commerce, 2125 Rayburn 

House Office Building, Washington, DC 20515 and e-mailed in Word format to 

Kel!y.CoJiins@mail.house.gOV. 

Thank you again for your time and effort preparing and delivering testimony before the 

Subcommittee. 

cc: Tbe Honorable Bobby L. Rush, Ranking Member, Subcommittee on Energy 

Attachment 
153 


30978.123

House Energy and Commerce Committee 

Energy SubCommittee 

Additional Questions for the Record 

The Honorable Fred Upton 

1. Are Non-Transmission Alternatives such as energy storage, DER, and smart technologies 

receiving adequate consideration from transmission-owning utilities? Do incentives exist that 

would otherwise discourage utilities from adopting cheaper alternatives that would reduce costs 

for customers? 

The incentives of transmission owners regulated under cost-of-service regulation with formula rates is 

to put more capital into the rate base and collect the return. This can be beneficial in cases where new 

transmission lines are needed and where there are not viable alternatives. That tends to be the case 

with accessing major remote renewable energy areas or to address persistent large regional or interregional congestion, where more transmission is generally needed. In some cases such as with MISO's 

Multi-Value Projects, each of these multiple types of value were considered together, yielding $12 

billion to $53 billion in net benefits, or between $250 and $1,000 for each person currently served by 

MISO, as I explained in my written testimony. 

However there are many other situations where new transmission is not needed, or there are viable 

alternatives that are cheaper. Normally with cost-of-service regulation, such as that performed by state 

public utility regulatory commissions, there is an assessment of need and consideration of alternatives 

prior to granting the utility the right to construct the facility and charge customers. FERC does not do 

that with transmission. Instead, utilities build transmission and file informational filings to FERC. There 

is not a process to consider alternatives. There are many situations where even technologies that are 

clearly part of the transmission system, that attach to the wires or help manage flows on the wires more 

efficiently, are being overlooked. Dynamic line Ratings, power flow control, network topology 

optimization, and some applications of energy storage fit in this category as technologies clearly serving 

only a transmission function and should be considered as alternative transmission options. 

There are also claims by many parties that distributed resources such as those at the end-users' 

locations behind the meter should be incorporated as non-wires alternatives and incorporated into 

transmission rates. FERC has the difficult job of determining whether those resources should be treated 

differently than generation, since both are serving other functions though they can reduce congestion or 

serve as an alternative to transmission to manage a contingency. To some extent, there is an incentive 

in energy markets for some of these options because locational prices signal to generation, DERs, and 

demand response to respond, both in the short and long run, when congestion causes high prices in an 

area. FERC will need to draw a line between what qualifies as transmission facilities and what does not. 

2. There's been some concern that utilities have an incentive to undertake large-scale transmission 

projects that aren't necessary for reliability, or to forgo lower cost alternatives that would avoid 

building new lines. What changes could be made to reduce this incentive so we can avoid 

making large investments in transmission when cheaper alternatives are available? 
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30978.124

I recommend three changes that FERC and its Congressional oversight committees can 

promote: 

1) Change the incentive: 

a. Entertain utility filings under section 205 of the Federal Power Act to modify 

rate design to provide the transmission owner with an incentive to reduce 

congestion. Other countries have promising models that could be used. 

FERC has not yet expressed any openness to entertaining such proposals, 

though I am optimistic that the current set of Commissioners are interested 

in promoting innovation, especially in areas such as this one that can 

increase system reliability and resilience. 

b. Review incentive policy generally. As I explained in my written testimony, 

addressing incentives (other than return on equity for new lines) was never 

implemented by FERC after the Energy Policy Act of 2005, and is an 

important piece of unfinished business. 

2) Improve planning. FERC should provide planning guidance to regional transmission 

planners about the use of advanced technologies to solve transmission needs. For 

example, RTOs and ISOs have planning protocols for market efficiency, yet none of 

them have a clear means for advanced grid utilization technologies to be considered. 

3) Informally promote the consideration of all options and share best practices. Many 

of these options are new, and new technologies in regulated sectors generally have 

a hard time breaking in unless the regulator expresses interest in supporting them. 

This need not require "picking winners," only allowing new entrants into the contest 

and clarifying how rules and standards apply to them. 
155 

Æ 


30978.125

House Energy and Commerce Committee 

Energy SubCommittee 

Additional Questions for the Record 

The Honorable Richard Hudson 

1. On Aprill9, FERC issued a new rule (Order No. 845) concerning revisions to the interconnection 

process for large generators which are over 20 MWs. The intent of this rule is to reduce the 

backlog of interconnection queue requests ... Do you believe that this new interconnection rule 

will alleviate these backlogs? 

I believe FERC Order 845 will significantly improve generator interconnection queue problems. As FERC 

concluded, "the reforms adopted in this Final Rule will help improve the efficiency of processing 

interconnection requests for both transmission providers and interconnection customers, maintain 

reliability, balance the needs of interconnection customers and transmission owners, and remove 

barriers to resource development." 

However, by itself, no interconnection policy can really solve the problem. There must also be a change 

to transmission planning to sufficiently incorporate future growth in and locations of new locationconstrained generation. For example, there is solid information on where renewable resource areas 

are, and sufficient certainty based on relative economics (even ignoring clean energy or climate 

policies), that certain resource areas will be developed. Yet transmission planning operates in a vacuum, 

separate and independent from generation development and interconnection queues. Queue 

challenges have been avoided where transmission planning explicitly incorporated likely locations of 

new generation development. California and Texas have done this better than other regions, and 

MISO's Multi-Value Projects are a good example of such a process. When transmission planning fails to 

account for the amount and locations of future generation development, then large "network upgrade 

costs" get assigned to individual generators which are like charging the next car on a highway the cost of 

a lane expansion, or the next home in a subdivision the cost of the new road. Placing that burden on the 

next generator will inevitably cause that generator to drop out of the queue or change its plans, causing 

frustration for the transmission provider and generators alike. 

2. How would modifications made by interconnection customers affect the interconnection studies 

of later-queued requests? 

When there is a large network upgrade cost assignment at stake, which is the case when transmission 

planning fails to account for the amount a locations of new generation development, then each 

generator faced with such a charge will have a strong incentive to modify their plans in various ways to 

avoid or reduce the charge. FERC's Order No. 845 accepted some but not all of the recommendations 

by generators to improve the process. Yet the problem will not be fully solved until transmission 

planning and generation interconnection processes are better coordinated.