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POWERING AMERICA: EXAMINING THE ROLE OF 

FINANCIAL TRADING IN THE ELECTRICITY MARKETS 

HEARING 

BEFORE THE

SUBCOMMITTEE ON ENERGY 

OF THE

COMMITTEE ON ENERGY AND 

COMMERCE 

HOUSE OF REPRESENTATIVES 

ONE HUNDRED FIFTEENTH CONGRESS 

FIRST SESSION 

NOVEMBER 29, 2017 

Serial No. 115–81 

( 

Printed for the use of the Committee on Energy and Commerce 

energycommerce.house.gov 

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 

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 

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) 

(II) 

(III) 

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 .......................................................................................... 2 

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

opening statement ................................................................................................ 3 

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

prepared statement .............................................................................................. 127 

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

New Jersey, prepared statement ........................................................................ 127 

WITNESSES

Wesley Allen, Chief Executive Officer, Red Wolf Energy Trading, on Behalf 

of Financial Marketers Coalition ........................................................................ 5 

Prepared statement .......................................................................................... 7 

Answers to submitted questions ...................................................................... 131 

Eric Hildebrandt, Ph.D., Director, Department of Market Monitoring, California Independent System Operator Corporation ............................................ 23 

Prepared statement .......................................................................................... 25 

Answers to submitted questions ...................................................................... 145 

Max J. Minzner, Partner, Jenner & Block, LLP ................................................... 57 

Prepared statement .......................................................................................... 59 

Answers to submitted questions ...................................................................... 161 

Noha Sidhom, Chief Executive Officer, TPC Energy, LLC, on Behalf of the 

Power Trading Institute ...................................................................................... 66 

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

Answers to submitted questions ...................................................................... 165 

Vincent P. Duane, Senior Vice President, Law, Compliance & External Relations, PJM Interconnection, LLC ........................................................................ 88 

Prepared statement .......................................................................................... 90 

Answers to submitted questions ...................................................................... 175 

Christopher Moser, Senior Vice President for Operations, NRG Energy, Inc. ... 97 

Prepared statement .......................................................................................... 99 

Answers to submitted questions ...................................................................... 183 

SUBMITTED MATERIAL

Letter of November 27, 2017, from Joseph Bowring, Independent Market 

Monitor for PJM, to Mr. Upton and Mr. Rush, submitted by Mr. Upton ....... 129 

(1) 

POWERING AMERICA: EXAMINING THE ROLE 

OF FINANCIAL TRADING IN THE ELECTRICITY MARKETS 

WEDNESDAY, NOVEMBER 29, 2017 

HOUSE OF REPRESENTATIVES, 

SUBCOMMITTEE ON ENERGY, 

COMMITTEE ON ENERGY AND COMMERCE, 

Washington, DC. 

The subcommittee met, pursuant to call, at 10:17 a.m., in room 

2322, Rayburn House Office Building, Hon. Fred Upton (chairman 

of the subcommittee) presiding. 

Members present: Representatives Upton, Olson, Barton, Shimkus, Harper, McKinley, Griffith, Johnson, Flores, Mullin, Hudson, 

Walberg, Rush, McNerney, Peters, Green, Sarbanes, Welch, Tonko, 

Loebsack, and Schrader. 

Staff present: Samantha Bopp, Staff Assistant; Allie Bury, Legislative Clerk, Energy/Environment; Zack Dareshori, Legislative 

Clerk; Wyatt Ellertson, Professional Staff Member, Energy/Environment; Jordan Haverly, Policy Coordinator, Environment; A.T. 

Johnston, Senior Policy Advisor, Energy; Mary Martin, Chief Counsel, Energy/Environment; Alex Miller, Video Production Aide and 

Press Assistant; Brandon Mooney, Deputy Chief Counsel, Energy; 

Mark Ratner, Policy Coordinator; Annelise Rickert, Counsel, Energy; Dan Schneider, Press Secretary; Peter Spencer, Senior Professional Staff Member, Energy; Jason Stanek, Senior Counsel, Energy; Rick Kessler, Minority Senior Advisor and Staff Director, Energy and Environment; John Marshall, Minority Policy Coordinator; and Alexander Ratner, Minority Policy Analyst. 

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

Mr. UPTON. Good morning, everybody. So, at our last Powering 

America hearing, we examined the important role that consumer 

advocates play in the organized electricity markets. Today, our examination of these markets continues as we turn our attention to 

the role of financial market participants, both why they trade financial products and the effects that their transactions have in the 

Nation’s seven RTO and ISO markets. 

With us today are witnesses who have extensive experience in 

trading financial products on behalf of private institutions and a 

major utility. We also have a rep from PJM Interconnection, the 

world’s largest wholesale electricity market and the market monitor for the California independent system operation, so welcome. 

2 

Financial market participants are playing an increasingly visible 

role in the organized wholesale electricity markets. It is claimed 

that financial transactions can improve the efficiency of the physical electricity markets by providing increased liquidity, mitigating 

market power, and improving price formation. 

In this hearing, I hope that the witnesses will explain their perspectives regarding why we have financial trading in the organized 

electricity markets and how this trading affects consumers who ultimately pay for electricity services. 

Each of the RTOs and ISOs allow financial trading to occur in 

their markets including PJM and the California ISO. The most 

commonly traded financial products are known as financial transmission rights or FTRs and virtual transactions. While these products can by used by traditional utilities to hedge themselves 

against volatile price fluctuations, these products are also bought 

and sold by financial traders such as banks, investors, and other 

speculators. 

While financial market participants ultimately trade to make a 

profit, for sure, advocates for trading claim that financial transactions strengthen the markets by increasing trading volume and 

liquidity which in turn reduces volatility and risk. Financial traders also claim to provide for the needs of physical market participants by offering services such as customized hedges and various 

types of options to limit the risk. 

However, measuring the overall contribution and benefits of financial transactions in the electricity markets are certainly difficult. Critics of financial trading argue that both FTRs and virtual 

transactions extract value from the market without providing 

equivalent benefits in return. I also understand the FERC is currently reviewing several hotly debated proposals which would reduce the opportunities for virtual transactions to be used to profit 

from the market without adding commensurate value. 

Not surprisingly, many financial traders are opposed to those 

proposals and as our Powering America series extends into next 

year, we will continue to tackle some of the most complex and challenging issues concerning both electricity markets and the energy 

industry. Along those lines today, our job is to take a hard look at 

whether FTR and virtual trading market makes sense and answer 

the question, does financial trading make the electricity markets 

more efficient and in turn result in benefits to consumers? 

So with that I yield to the ranking member of the subcommittee, 

my friend from Illinois, Mr. Rush. 

[The prepared statement of Mr. Upton follows:] 

PREPARED STATEMENT OF HON. FRED UPTON

Good morning. At our last Powering America hearing, we examined the important 

role that consumer advocates play in the organized electricity markets. Today, our 

examination of these markets continues as we turn our attention to the role of financial market participants—both why they trade financial products and the effects 

that their transactions have in the Nation’s seven RTO and ISO markets. 

With us today are witnesses who have extensive experience in trading financial 

products on behalf of private institutions and a major utility. We also have a representative from PJM Interconnection—the world’s largest wholesale 

electricitymarket; and the market monitor for the California Independent System 

Operator. Welcome. 

3 

Financial market participants are playing an increasingly visible role in the organized wholesale electricity markets. It’s claimed that financial transactions can improve the efficiency of the physical electricity markets by providing increased liquidity, mitigating market power, and improving price formation. In this hearing, I hope 

the witnesses will explain their perspectives regarding why we have financial trading in the organized electricity markets and how this trading affects consumers who 

ultimately pay for electricity services. 

Each of the RTOs and ISOs allow financial trading to occur in their markets, including PJM and the California ISO. The most commonly traded financial products 

are known as ‘‘Financial Transmission Rights’’ or ‘‘FTR’s’’ and ‘‘Virtual Transactions.’’ While these products can be used by traditional utilities to hedge themselves against volatile price fluctuations, these products are also bought and sold by 

financial traders such as banks, investors, and other speculators. 

While financial market participants ultimately trade to make a profit, advocates 

for trading claim that financial transactions strengthen the markets by increasing 

trading volume and liquidity, which in turn reduces volatility and risk. Financial 

traders also claim to provide for the needs of the physical market participants by 

offering services such as customized hedges and various types of options to limit 

risk. 

However, measuring the overall contribution and benefits of financial transactions 

in the electricity markets is difficult. Critics of financial trading argue that both 

FTRs and virtual transactions extract value from the markets without providing 

equivalent benefits in return. I also understand that FERC is currently reviewing 

several hotly debated proposals which would reduce the opportunities for virtual 

transactions to be used to profit from the market without adding commensurate 

value. Not surprisingly, many financial traders are opposed to these proposals. 

As our Powering America series extends into next year, we’ll continue to tackle 

some of the most complex and challenging issues concerning both the electricity 

markets and the energy industry. Along those lines, today, our job is to take a hard 

look at whether FTR and virtual trading makes sense and answer this question: 

Does financial trading make the electricity markets more efficient, and in turn, result in benefits to consumers? 

I look forward to the testimony of our witnesses. 

Mr. UPTON. 

So with that, I yield to the ranking member of the subcommittee, 

my friend from Illinois, Mr. Rush. 

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

Mr. RUSH. Well, thank you, Mr. Chairman. And Mr. Chairman, 

I want to applaud you for holding this important hearing today. 

While we have an opportunity to examine the witnesses before 

us, we will be looking at the role of financial trading within the 

electricity markets. Mr. Chairman, while this may appear to be an 

obscure topic that the American people and even members of the 

subcommittee may not be intimately familiar with, it is important 

to keep in mind that these financial trading tools directly impact 

the cost that consumers pay for their electricity. 

In reviewing the testimony for today’s hearing, Mr. Chairman, 

there seems to be unanimous agreement that financial tools such 

as FTRs as well as day-ahead forward and real-time spot markets 

play key roles in improving the efficiency of the physical electricity 

market by providing increased liquidity, mitigating market power, 

and decreasing price volatility, all of which ultimately benefit 

America’s consumers. 

Additionally, Mr. Chairman, it has been noted that the FTRs 

provide forward pricing that helps gauge the need for additional infrastructure investment so that unnecessary construction and the 

subsequent costs associated with overbuilding are not passed on to 

the consumers. 

4 

However, Mr. Chairman, while all of our witnesses agree that 

these financial trading tools are indeed necessary, there also seems 

to be a consensus that some modifications may in fact be needed 

in order to ensure that these markets are operating in a way that 

is transparent, that is open, that is fair, and that is competitive. 

The discrepancy within the testimonies center around what reforms might be needed in order to adequately achieve these objectives. 

Specifically, Mr. Chairman, I look forward to hearing the panelists on two pending reform proposals forwarded by PJM that FERC 

is currently considering regarding the up-to Congestion or UTC 

transactions and how FERC’s decision will impact consumers. Additionally, I am interested to hear from our panelists on the recent 

DOE notice of proposed rulemaking and whether they support or 

oppose FERC providing additional subsidies to some form of generation, coal or nuclear, over and above other resources. 

Finally, Mr. Chairman, it can be no surprise that for me the 

most important factor in deciding whether any reforms are needed, 

with the panel, how they might impact consumers. I look forward 

to engaging our witnesses or their ideas for ensuring that RTOs 

and ISOs are first and foremost responsive to the needs of the customers. 

Additionally, I want to make sure that FERC has the tools, expertise, willingness, and authority to administer these financial 

markets in a way that would be fair, transparent, open, and competitive so that consumer interests are in fact the guiding principles and the most important priorities of the RTOs and the Commission. 

Mr. Chairman, I look forward to this hearing. 

Mr. UPTON. Thank you, my friend. 

It is my understanding that two other subcommittees are meeting at this same time, so Chairman Walden is going put his statement into the record. Are there any Members on our side that 

would like to use part of his 5 minutes? 

Seeing none, is there anyone on your side that needs Mr. 

Pallone’s time? 

Mr. RUSH. Ranking Member Pallone is also at another hearing. 

Mr. UPTON. So we will allow those opening statements to go in. 

[Mr. Walden’s and Mr. Pallone’s statements appear at the conclusion of the hearing.] 

Mr. UPTON. So we will move to the testimony, to our distinguished panelists. We are first joined by Wesley Allen, the CEO of 

Red Wolf Energy Trading, on behalf of the Financial Marketers Coalition. 

Thank you all in advance for submitting your testimony so that 

we could see it yesterday. And if you would summarize, each of you 

your testimony, in no more than 5 minutes, at which point we will 

do questions from the Members that are here. 

So Mr. Allen, welcome. You are recognized for 5 minutes. Thank 

you. 

5 

STATEMENTS OF WESLEY ALLEN, CHIEF EXECUTIVE OFFICER, 

RED WOLF ENERGY TRADING, ON BEHALF OF FINANCIAL 

MARKETERS COALITION; ERIC HILDEBRANDT, PH.D., DIRECTOR, DEPARTMENT OF MARKET MONITORING, CALIFORNIA 

INDEPENDENT SYSTEM OPERATOR CORPORATION; MAX J. 

MINZNER, PARTNER, JENNER & BLOCK, LLP; NOHA SIDHOM, 

CHIEF EXECUTIVE OFFICER, TPC ENERGY, LLC, ON BEHALF 

OF THE POWER TRADING INSTITUTE; VINCENT P. DUANE, 

SENIOR VICE PRESIDENT, LAW, COMPLIANCE & EXTERNAL 

RELATIONS, PJM INTERNCONNECTION, LLC; AND CHRISTOPHER MOSER, SENIOR VICE PRESIDENT FOR OPERATIONS, NRG ENERGY, INC. 

STATEMENT OF WESLEY ALLEN 

Mr. ALLEN. Good morning, Chairman Upton, Ranking Member 

Rush, and members of the subcommittee. Thank you for inviting 

me to share our opinions of the electricity markets. My name is 

Wesley Allen. I am CEO of Red Wolf Energy Trading, a small trading firm headquartered in Raleigh, North Carolina. I am representing the Financial Marketers Coalition which is a group of 

similarly situated companies transacting in the ISO/RTO markets. 

Red Wolf is a small company. We employ about a dozen employees scattered around the United States specializing in transacting 

the ISO/RTO energy markets. First and foremost, we support competitive markets. The transactions that we engage in clear the ISO 

day-ahead markets and then settle on the real-time. While we have 

been around for about 10 years, the type of activity we engage in 

has been around for longer and started when FERC began restructuring the electricity markets in the early 2000s. 

The purpose behind restructuring was to add competition and liquidity, price transparency, and to shift risk from consumers to investors. While the road to the restructuring wasn’t always smooth, 

after almost 20 years I believe it has been a success although there 

is room for improvement. The trading we do broadly is called virtual trading. Every ISO/RTO in the country allows virtual trading 

with one exception, the western Energy Imbalance Market. 

When the FERC was restructuring the electricity markets they 

realized without participation by companies like ours many of the 

goals they were trying to achieve would not be possible. One of the 

goals of restructuring was breaking up natural monopolies. Financial participation is the engine that drives competition and liquidity in the transparent RTO/ISO markets. 

Specifically, we engage in three types of transactions: an increment offer which sells electricity, a decremental bid which buys, 

and, lastly, a more refined ISO/RTO market such as ERCOT, a 

point-to-point transaction which is a basis or spread trade that 

transacts on the congestion between two locations on the transmission grid. 

Electricity is uniquely localized, and without participation in 

these markets generation and load-serving entities could exercise 

market power. Generation can exercise market power by economically withholding the electricity they supply. They could sell less 

power in the day-ahead but at a higher price. Think of what OPEC 

does in the oil markets. 

6 

But not all generation withholding is nefarious in nature. Some 

is risk management. Contracts awarded in day-ahead are financially binding. Some generators may opt not to schedule their full 

output in case the wind doesn’t blow or if they should have an 

equipment failure. Likewise, load can do something similar by underbidding their load and therefore buying most of their needs at 

a lower day-ahead price, then purchasing the remainder in the 

real-time. In these cases, virtual traders such as ourselves are assuming the risk that the utilities are unwilling to take. 

The purpose of the day-ahead is to pre-position the markets for 

the needs the next day. Electricity being a high/low class, it is necessary not only to commit the right amount of generation, but to 

commit generation in the right location in order to have an efficient 

and reliable market. Given the natural monopolies to the market 

power that would otherwise exist, financial participation is critical. 

A great deal of time in today’s hearing will be spent on the forward markets. While efficient forward markets are critical, so is 

price formation in day-ahead and real-time energy markets. If 

prices are incorrect in the day-ahead and real-time, then the wrong 

signals will be sent to the forward markets. The FERC has been 

working on price formation for some time now. The conclusions and 

improvements they have been working towards are going a long 

way to improve the markets. My only regret is it is taking a long 

time. 

Our participation in these markets has been under attack. Some 

have grown weary of competition and long for the former structure. 

That said, there have been a couple of notable electricity economists that through analyzing market outcomes have put a dollar 

figure on the efficiency gained by our participation. Dr. Wolak 

found that our participation in the California ISO increased market 

efficiency in the first year of virtual trading by $70 million per 

year. 

Additionally, Wolak found that by more efficiently committing 

and dispatching resources, our trading, virtual trading reduced 

greenhouse gas emissions by somewhere between 650- and 537,000 

tons annually. Dr. Patton, the independent market monitor at 

MISO, found that at a minimum financial market activity added 

$65 million in increased efficiency. 

While most recognize that virtual trading adds efficiency in RTO/ 

ISO markets, more could be achieved. Nearly half of all virtual 

transactions at less refined ISOs are done in a price-insensitive 

manner. More refined ISOs allow basis tradings, specifically 

ERCOT. Dr. Patton has been advocating for this product at MISO 

for over 5 years. With implementation scheduled for several years 

from now, we believe these critical changes are taking too long. 

In conclusion, virtual traders add efficiency to ISO/RTO markets 

by injecting competition and liquidity that would be absent without 

them. Thank you and I look forward to your questions. 

[The prepared statement of Mr. Allen follows:] 

7 


Written Testimony of 

Wesley Allen 

CEO, Red Wolf Energy Trading 

On Behalf of the Financial Marketers Coalition 

Before the 

House Energy Subcommittee 

Hearing on 

"Examining the Role of Financial Trading in the Electricity Markets" 

November 29, 2017 

I. Market Basics 

II. Availability of Financial Products 

a. Need for Increased Availability of Transmission Congestion Products 

III. Value of Competition and Proper Price Formation 

IV. Wholesale Markets Work and Must be Allowed to Continue Working 

a. Concerns with the Department of Energy's Notice of Proposed Rulemaking 

V. Academic Studies Have Confirmed and Quantified the Benefits of Financial Transactions 

VI. ISO/RTO Markets Should Better Accommodate Minority Interests 

{W5432404,2} 
8 


Financial trading and the presence of financial market participants play a critical role in 

allowing the regional electricity markets operated by the independent system operators ("ISO") 

and regional transmission organizations ("RTO") (collectively, "ISO/RTO") to deliver benefits 

to all participants in those markets, including consumers. Unique among market participants, 

financial participants focus solely on how prices are formed, and profit only when they 

contribute to better forward market prices. The same incentives do not exist for physical 

participants, meaning that the only stakeholders working to ensure that the ISOIRTO markets 

provide useful price signaling for short-term and long-term decision-making are financial 

participants. 

Market Basics 

Broad themes like liquidity, price formation, outcome forecasting, competition and 

efficiency are central to any discussion of how markets work, but truly appreciating the value 

that financial participants drive in the context of regional electricity markets comes from better 

understanding the nuts and bolts of the markets, and the predictable ways in which they fail in 

the absence of financial participants. 

The ISOIRTOs operate a number of markets that provide price signals for a range of 

times, ranging from minutes to years into the future. Financial transactions in the ISOIRTO 

wholesale markets happen primarily in the longer-term Financial Transmission Rights ("FTR") 

auctions which will be addressed by a colleague on the panel, and the Day-Ahead markets. I 

note there is also energy derivatives trading outside of the ISO/RTO markets, such as on the 

Intercontinental Exchange ("ICE") and other platforms, but derivatives are outside the scope of 

our conversation today. 

{W6432404.2) 2 
9 


The cornerstone of ISO/RTO markets is Locational Marginal Pricing ("LMP"). All of 

the ISO/RTO markets differentiate pricing by location. All demand and supply pay (or are paid) 

the same prevailing price, and that price is the marginal cost of satisfying the next megawatt of 

demand. LMP consists of three components: 

System Energy Price: the price of serving the last MW of demand across the entire 

grid 

Marginal Loss: a de minimis amount reflecting grid conductor properties 

Congestion Price: This is only non-zero when the system is constrained - i.e., when 

lower cost units could produce more if not for grid transmission issues 

The congestion component is the driver of different prices in different locations on the grid. 

When constraints in grid transmission restrict the availability of generation, prices differentiate 

resources near to demand from those that are far away, or that cannot reach demand due to the 

unavailability of constrained transmission lines. 

The power of LMP is that it intertwines short-term dispatch instructions with clear 

signaling to the rest of the market. Lowering the output of a given plant is accomplished by 

sending that particular plant (and other generators in the same region) a lower price. Should 

other plants need to produce more power, those plants and others nearby arc signaled to do so by 

a higher price. 1 In each case, the short term outcome (more or less power) is accompanied by a 

transparent signal to any other interested stakeholder: lower prices equate to relatively less need, 

and higher prices equate with relatively more need. 

These market signals are sent through the Day-Ahead (forward) and Real-Time (spot) 

markets. The Real-Time market thus relies heavily on the Day-Ahead market to posture the right 

resources to allow for reliable operation of the grid; failure of the Day-Ahead market to make 

1 ISOIRTO operators retain the ability to dispatch specific facilities as needed, through out-ofmarket mechanisms, including to meet reliability needs. 

{W6432404.2) 3 
10 


those correct resources available results in high volatility in the Real-Time market, as the system 

operator struggles to satisfy instant demand, with a set of resources poorly matched to the 

location and magnitudes of demand. 

Unfortunately for the grid operator, the Day-Ahead market naturally contains incentives 

for physical participants to behave differently than they will in the Real-Time market. In 

general, those serving load can maximize their short run profits by purchasing less power in the 

Day-Ahead market than they expect to use in Real-Time. By purchasing less than they know 

they will need, they shift the supply and demand intersection in a way that reduces price. On the 

other hand, generators can maximize their short run profits (or manage their Real-Time risks) by 

offering slightly less power into the Day-Ahead market than they expect to be able to produce. 

This has the effect of shifting the supply demand intersection in the opposite direction. Figures 1 

and 2 demonstrate the impacts on pricing of both load (demand) and generation (supply) 

underbidding into the Day-Ahead market. 

Fig. 1- Example of Load Underbidding Fig. 2 -Example of Generation Underbidding 

In each case, the supply curve is shifted as a result of the underbidding. In the case of load 

underbidding, less power is procured in the Day-Ahead market resulting in lower Day-Ahead 

prices. In the case of generation underbidding, less power is available in the Day-Ahead market, 

{W6432404.2} 4 
11 


resulting in higher Day-Ahead prices. The market prices power on a locational basis, so both 

dynamics can play out at the same time at different locations on the power grid. The long term 

effect of this push-pull of the supply and demand curves are Day-Ahead market prices that 

diverge further and further from the Real-Time market. Fortunately, there are participants in the 

market whose sole avenue for profiting comes from identifying where the forward market is 

failing to price things correctly, and pushing the forward market behavior to more closely match 

the spot market outcomes. Figures 3 and 4, below, demonstrate how financial market 

participants can converge the Day-Ahead and Real-Time markets by more accurately forecasting 

Real-Time conditions to pre-position the Day-Ahead market. 

Fig 3. Actual MISO DA Market Demand Curves, 6/3/2016, 

Physical Market Participants Only 

{W64:H404.2} 5 
12 


Fig. 4. Actual MISO DA Market Demand Curves, 6/3/2016, 

With Financial Market Participants (DECs) 

On June 3, 2016 in the Real-Time, actual physical demand was 85 GW but physical load 

participants purchased only 95% of that amount, thus underbidding by 5% or almost 4 GW. 

Only 2% of the load bid in Fig. 3 was bid in a price sensitive manner. In Fig. 4 above, financial 

market participants added nearly 10 GW in liquidity, sending a strong signal to the market of the 

need for additional power. 

A vail ability of Financial Products 

Each of the ISO/RTOs have varying financial products available. While FTRs, as well as 

virtual supply and demand bids, are fairly common, transmission congestion products are less 

common. The existence of these products is essential not only to price formation, but also the 

ability of market participants to hedge in a price sensitive manner. In particular, hedging is 

relevant not only to financial market participants, but all forms of market participants, including 

competitive retail electric suppliers, who need to hedge transmission congestion risks. 

(W643"2404,2} 6 
13 


Fig. 5. Financial Products in the ISO/RTO Markets 

The energy products in most ISO/RTO markets are increment offers ("INC") and decrement bids 

("DEC"), which allow a market participant, financial or otherwise, to take a position on the LMP 

at a given node. That position is exposed to all three elements of LMP: energy price, congestion 

and losses. As such, the position bears not only risks associated with transmission congestion, 

but also with resulting energy prices. A product allowing market participants to take a position 

on the transmission congestion between two given points without exposure to the fluctuations of 

energy prices, allows for more granular contributions to price formation without the risk and 

exposure that can prove challenging to market participants whose goal is to utilize the product 

specifically to hedge risk. 

{W6432404.2) 7 
14 


Fig 6. Lack of an Hourly Congestion Product is a Concern 

Energy Products 

Transmission Products 

While ERCOT offers the Point-to-Point product and PJM offers the Up-To Congestion ("UTC") 

product, most of the other markets do not offer a congestion and losses product in their DayAhead markets. We note that the ERCOT market is particularly vibrant and liquid, due in part to 

the presence of the Point-to-Point product, which facilitates hedging by load-serving entities.2 

While PJM does offer the UTC product, its availability is limited. NYISO, MISO and CAISO 

have considered adding such a product and are at various stages of development, with NYISO 

and MISO estimating a 2020 deployment. We believe that the expansion of financial products in 

ISO/RTO markets, to include the development of a congestion and losses product in the DayAhead market, should be a priority. 

Value of Competition and Proper Price Formation 

As discussed above, financial transactions move the supply and demand curve to help 

compensate for potential underbidding by other market participants, including load and 

2 Interestingly, in ERCOT, physical asset owners are the primary users of the Point-to-Point 

product, with financial market participants representing 20% or less of entities engaging in these 

transactions. In PJM, those numbers are reversed. See, e.g., ERCOT State of the Market Report 

at 32, available at https://www.potomaceconomics.com/wp-content/uploads/2017/06/2016-

ERCOT-State-of-the-Market-Report.pdf 

iW6432404.2) 8 
15 


generation. Another way to view this shift in the supply curve is through the lens of depth and 

liquidity, which are highly valuable and essential to market efficiency in all commodity markets. 

In organized markets with LMP pricing, depth and liquidity are even more essential because 

electricity, unlike other commodities, cannot be stored. Depth in a market is a significant 

number of bids and offers at each of the nodes within the system. If a load-serving entity wishes 

to purchase electric energy in the Day-Ahead market, it would like to see a wide variety of offers 

to sell, which are tightly spaced. For example: 

Bid Stack A 

50 MW for $50.00 

I 0 MW for $65.00 

25 MW for $75.00 

15 MW for $85.00 

Bid Stack B 

50 MW for $50.00 

5 MW for $52.00 ~ INC offer 

5 MW for $54.00 ~ INC offer 

I 0 MW for $55.00 

25 MW for $60.00 

15 MW for $63.00 

The load-serving entity would prefer to meet its Day-Ahead needs in a market that looks more 

like Bid Stack B because there are more choices available to the system operator and the 

presence of more bids has exerted a downward pressure on the prices. In this example, the two 

virtual offers in Bid Stack B have smoothed out the "lumps" in the bid stack, introduced 

competition which has exerted downward pressure on prices, and added liquidity and depth to 

the market. 

Additionally, electricity markets must balance every hour at every location. If demand is 

low in the Day-Ahead market compared to what is likely in the Real-Time market, then DECs 

placed in the Day-Ahead market will help bring that demand up to what it is expected to be. 

Conversely, if supply is low in the Day-Ahead market, then INCs placed in the Day-Ahead 

market will help bring that supply closer to what it is expected to be in the Real-Time market. 

Convergence between the Day-Ahead and Real-Time markets is important because converged 

{W6432404.2} 9 
16 


markets yield lower prices to consumers. Second, energy markets are inherently volatile and 

risky because it can be hard for market participants to predict, in the Day-Ahead market, what 

the Real-Time market will look like. Financial marketers shoulder this risk on behalf of other 

market participants, allowing market participants to hedge the prices that they will pay against 

the trades placed by a financial market participant. Financial marketers also bring needed 

liquidity and competition to markets, and introduce competition where otherwise none (or little) 

may exist. 

Wholesale Competitive Electricity Markets Work and Must Be Allowed to Continue Working 

The Financial Marketer Coalition's focus is on strong, competitive markets. We believe 

that markets work and should be allowed to work with minimal government intervention, 

particularly in the form of out-of-market subsidies. Such out-of-market payments can distort 

market outcomes, yielding competitive advantages to one (or two) class of market participants, 

who may not otherwise be competitive. In late September, the Department of Energy submitted 

a draft Notice of Proposed Rulemaking ("NOPR") to FERC, proposing to compensate electric 

generation facilities for stockpiling fuels, in essence particularly providing subsidies to coal and 

nuclear fueled facilities. As you are aware, a bipartisan group of former FERC Chairmen filed 

comments with FERC stating that the DOE NOPR proposal will "fundamentally distort" 

markets, and urging FERC to reject or significantly modify the proposal. 

Many have raised concerns about the potential damage to the ISO!RTO markets from 

financial subsidies and out-of-market payments given to certain classes of generators, 

particularly given the generous incentives already provided to such resources, including the 

benefits associated with paying the lowest effective federal tax rate of any business sector. Of 

the 40 U.S. publicly held utility companies that were profitable in 2015, 23 paid no federal 

{W6432404.2j 10 
17 


income taxes and 16 paid no state taxes, while earning a combined $43.9 billion dollars in pretax profits. 3 Regulated utilities have the luxury of building corporate taxes into the rate plans set 

by regulators and passed on in charges to the customer. Special tax laws and utility rate plans 

further provide the opportunity for utilities to postpone taxes through accelerated depreciation, 

allowing companies to delay paying tax on the cost of their investments while receiving 

essentially interest-free loans. The 23 profitable utilities that paid no federal tax in 2015 reported 

$11.5 billion in benefits from special tax rules that allow corporations to write off the costs of 

infrastructure investments. 4 

A direct result of this special tax treatment is increased costs to consumers stemming 

from prolific and unnecessary infrastructure enhancements. Although there is a need to replace 

aging infrastructure and accommodate distributed generation resources, a recent trend 

demonstrates an increase in transmission enhancements lacking a legitimate driver such as 

reliability, market efficiency or operational performance criteria. 5 The majority of new 

transmission projects are not needed are used merely as vehicles for utilities to amortize costs 

and increase profits by passing on depreciation rates to customers. 

The NOPR will effectively provide a bailout for utility companies making billions in 

profits per year, to the harm of low-income consumers. Utilities profit by purchasing power on 

the wholesale market and reselling the same power to retail consumers at a premium. In August, 

which is a peak month, the price of wholesale power in California was approximately 

3 Anderson, Sarah et al., Utilities Pay Up: How Ending Tax Dodging by America's Electric 

Utilities Can Help Fund a Job-Creating, Clean Energy Transition, Institute for Policy Studies at 

I (July, 20 16), available at http://www.ips-dc.org/wp-content/uploads/20 16/07 /IPS-UtilitiesTax-Report-FINAL.pdf. 

4 !d. 

5 American Municipal Power, Inc., Transmission Costs Drivers at 10 (Sept. 21, 2017), available 

at http://www.amppartners.org/ Assets/ AMP Rose Transmission.pdf. 

{W64:U404,2} 11 
18 


$39/MWh.6 In contrast, the price of retail power for residential end-users was 19.02 cents per 

kWh, or $190/MWh.7 In addition to profiting from the price difference between wholesale and 

retail power, certain types of generation resources benefit from federal and state incentive 

programs, such as Zero Emission Credits ("ZECs") for carbon neutral resources. Nuclear 

resources could be eligible for ZEC environmental subsidies even when found to be leaking 

radiation in the environment. 8 Providing additional subsidies to uneconomic and 

environmentally harmful resources is inconsistent with market fundamentals and results in actual 

harm to consumers. If there are important externalities that the market currently does not value, 

whether that is the environmental and global impact of carbon or the need for resiliency, then 

those externalities should be brought into the market. This has been done in other contexts -

through mandatory reliability standards as well as the creation (and expansion) of the ancillary 

services markets within the ISO/RTO markets. 

The wholesale competitive electricity markets operated by the ISO/RTOs work, and 

subsidies harm market equilibrium by distorting market signals and prices for consumers. The 

benefits brought by these markets have been quantified in many ways, including through lower 

costs to retail consumers in consumer-choice states. Recently the COMPETE Coalition released 

a report showing the demonstrable benefits of competitive electricity markets, noting that from 

1997 through 2014, prices in consumer-choice jurisdictions increased 4.5% less than inflation, 

6 This number was calculated by Red Wolf Energy Trading internally, based on CAl SO's 

published data. 

7 Electric Power Monthly Data for August 2017, Table 5.6.A. Average Price of Electricity to 

Ultimate Customers by End-Use Sector, by State (Oct. 24, 2017), available at 

https://www.eia.gov/electricity/monthly/epm table grapher.php?t=epmt 5 6 a. 

8 Chase, Brett et al., Radioactive Water Leaks from Illinois Nuclear Plants, Better Government 

Association (Nov. 17, 2017), available at https://projects.bettergov.org/powerstruggle/?utm source=Sailthru&utm medium=email&utm campaign=lssue:%202017-ll20%20Utility%20Dive%20Newsletter%20%5Bissue:l2938%5D&utm term=Utility%20Dive. 

{W6432404.2) 12 
19 


while prices in regulated jurisdictions rose 8.4% more than inflation. Stated another way, the 

authors found that "[b]etween 1997 and 2014, all-sector nominal weighted average prices in 

Customer Choice Jurisdictions rose by 41%, but rose by 60% in the Monopoly States." 9 These 

prices are real costs - and real savings to real consumers. 

Academic Studies Have Confirmed and Quantified the Benefits of Financial Transactions 

In the past several years, the value that financial marketers bring to the market has been 

questioned. Some have asked whether the value financial marketers bring to the market exceeds 

the value that they extract from the market. We firmly believe that financial marketers bring 

benefits to the market significantly in excess of the cost of their participation. A study by two 

economists at Stanford University found that the introduction of Convergence Bidding in 

California created significant economic and environmental savings for consumers. 10 The study 

found that those savings specifically came in two areas. 

>- First, the annual total cost of fossil fuel energy decreased by about roughly $70 million 

dollars per year in the year following the introduction of Convergence Bidding, through 

more efficient unit commitment. 

>- Second, the study found, Convergence Bidding resulted in a reduction of greenhouse gas 

emissions of approximately 2.8%, or between 537,000 and 650,000 pounds of emissions 

annually, again through better underlying unit commitment. 11 

9 O'Connor, P. and O'Connell-Diaz, E., Evolution of the Revolution: The Sustained Success of 

Retail Electricity Competition at 5-7 available at 

https ://sites .hks.harvard.edu/hepg/Papers/20 I 5/Massey Evolution%2 Oof"/o2 0 Revolution. pdf 

10 JHA, A AND WOLAK, F, Testing for Market Efficiency with Transaction Costs: An Application 

to Convergence Bidding in Wholesale Electricity Markets at 23 (May 7, 2013) available at 

http://web.stanford.edu/group/fwolak!egi-bin/sites/defaultlfiles/files/CAISO VB draft VS.pdf. 

11 This occurred through the pre-positioning of the Day-Ahead market, allowing more efficient 

units to run instead of the system operator calling on less-efficient units in the Real-Time market. 

(W6432404.2) 13 
20 


At the same time that year, the profits extracted from the market by entities trading Convergence 

Bidding was approximately $13 million in 20 II and $18 million in 2012. 12 While this study was 

done in the smaller CAISO market, it shows profound savings - with Convergence Bidding 

bringing value over four times greater than the cost of such trading in fuel costs alone, not 

including the value of avoided carbon emissions, and the longer term value of better pricing in 

the forward market to all market participants. Specifically, the study noted: 

Although it was possible to implicit virtual bid before the introduction of explicit 

virtual bidding, the evidence from our analysis is that the introduction of this 

product significantly improved the degree of price convergence between the dayahead and real-time markets and reduced the cost of serving load in the 

California ISO control area. 13 

Dr. John Parsons, in conjunction with the FERC Office of Enforcement, performed an 

analysis of convergence bidding in the CAISO markets, questioning the value of virtual 

transactions and referencing certain virtual bidding as "purely parasitic." Dr. Parsons' paper was 

highly skewed against virtual trading, seeking to find examples to prove that such transactions 

are not beneficial to competitive wholesale electricity markets. Dr. Parsons' analysis focused on 

ramping events in CAISO where virtual traders were consistently buying Day-Ahead energy and 

profiting from the ramping and scarcity pricing that occurs during the peak hours in California 

Note that the dollar value of reduced greenhouse gas emissions is not included in the $70 million 

savings. 

12 California Independent System Operator, Market Issues and Performance: 2011 Annual 

Report at 87 (2011), http://www.caiso.com/Documents/2011Annua1Report-MarketlssuesPerformance.pdf; California Independent System Operator, Market Issues and Performance: 

2012 Annual Report at I 09 (20 12), http://www.caiso.com/Documents/20 12Annua1ReportMarketlssue-Performance.pdf. We note that we refer only to the profits associated with internal 

Convergence Bidding, and do not include values associated with Convergence Bidding at the 

interties or in imports/exports. 

13 Wolak Study at 23 (emphasis added). Cf Parsons, J, Colbert, C., et al., Financial Arbitrage 

and Efficient Dispatch in Wholesale Electricity Markets at I (Feb. 20 15) (setting out to 

demonstrate in which circumstances virtual trading does not bring benefits, but not defining how 

frequently the hypothesis actually occurs). 

{W6432404.2) 14 
21 


when load is rising quickly and renewables are simultaneously ramping offline. The fatal flaw of 

Parson's analysis was in not rerunning the Real-Time results. Dr. Parsons failed to answer the 

critical question of whether the virtual transactions that were committing additional resources 

were lessening the frequency and severity of the shortage pricing events. Regardless, virtuals 

were committing additional generation in the Day-Ahead and making CAISO more reliable 

during scarcity events. 

But There Are Flaws in the ISO/RTO Markets 

While the Financial Marketers Coalition strongly supports the concept of the ISO/RTO 

markets, in practice, there arc issues to be addressed. The primary issue faced by minority 

interests such as financial market participants, is the strength of entrenched utility interests in the 

stakeholder process, the resistance of those interests to new market entrants and the deference 

that the staff of the ISO/RTOs give to these incumbent interests. During the last Powering 

America hearing, Ranking Member Bobby Rush (D-IL) welcomed discussion on the market 

issues associated with RTOs beholden to incumbent utilities: 

As we will soon hear, Mr. Chairman, many consumer advocacy groups believe 

that the RTOs are too beholden to the utilities than they are trying to administrate. 

And consumers do not have a large enough seat at the table to make their voices 

heard. Many of these advocates argue that the whole process for reforming 

energy markets have become more and more complex, while at the same time 

consumer voices have been diluted to the point of being completely shut out. 

There also seems to be, a new consensus, Mr. Chairman, among today's 

witnesses, that FERC and DOE have become too tolerant of the RTOs' ability to 

shut out public interests, and participation, and policymakers must act to address 

this challenge. 14 

Ranking Member Rush's concerns are very accurate, but they extend past consumers to 

encompass all minority interests in the ISO/RTO stakeholder process, among them financial 

14 Transcript of Powering America: Consumer-Oriented Perspectives on Improving the Nation's 

Electricity Markets at 3-4 (Oct. 7, 2017), available at http://docs.house.gov/meetings/ 

IF/IF03/20 171005/1 06470/HHRG-ll5-IF03-Transcript-20 171 005.pdf 

!W6432404.2} 15 
22 


market participants. Recent initiatives in the PJM stakeholder process to essentially eliminate 

the UTC product by imposing a double tax through uplift payments and reducing by over 90% 

the points at which such transactions may be placed, highlight these stakeholder process 

concerns. These proposals are currently pending at FERC, where we have strongly argued that 

FERC must act to protect financial trading and send a strong message to the ISO!RTO, its staff 

and stakeholders regarding voting and process irregularities. 

Conclusion 

In conclusion, the Financial Marketers Coalition greatly appreciates the opportunity to 

testify to the Subcommittee on the role and importance of financial trading in wholesale 

competitive electricity markets operated by the ISO/RTOs. We believe that the markets work, 

and should be allowed to continue working. We also believe that financial trading is a key 

element in maintaining competition, liquidity and good price formation in those markets. We do 

see areas for improvement and look forward to working with the Subcommittee, FERC and the 

ISOIRTOs on these issues. 

{W64l2404.2} 16 
23 

Mr. UPTON. Thank you. 

Next, we are joined by Eric Hildebrandt, director of Market Monitoring for the California ISO. Welcome. 

STATEMENT OF ERIC HILDEBRANDT 

Dr. HILDEBRANDT. Good morning, Congressman. Thank you for 

inviting me today. My name is Eric Hildebrandt, director of Market 

Monitoring at the California ISO. The Department of Market Monitoring serves as the independent market monitor for the California 

ISO. The Federal Energy Regulatory Commission requires each 

ISO to have an independent market monitor whose mission includes, quote, ‘‘the protection of consumers and market participants 

by the identification and reporting of market design flaws and market power abuses.’’ 

My testimony today highlights a major market design flaw that 

exists in all ISOs which is costing transmission ratepayers at least 

$400 billion per year. This flaw involves the auctioning by ISOs of 

financial instruments called financial transmission rights or FTRs. 

California calls these congestion revenue rights or CRRs. 

Ratepayers of load-serving entities pay the full cost of the transmission system through transmission access charges and also higher prices when congestion occurs. All congestion revenues collected 

by ISOs should therefore be allocated back to transmission ratepayers. In fact, FTRs were initially developed as a way to fairly allocate congestion revenues back to the participants who pay for the 

transmission system. 

All ISOs currently allocate FTRs to load-serving entities based on 

their projected use of the transmission system. We support continued use of FTRs in this way to provide load-serving entities with 

a hedge that offsets the congestion costs they may incur. However, 

we believe that all additional congestion revenues that remain 

after settlement of these allocated FTRs should also be refunded to 

transmission ratepayers. 

Currently, however, after allocating FTRs to load-serving entities, ISOs then auction off additional FTRs. These FTRs are essentially price swaps. But unlike price swaps for other commodities, 

FTRs are not cleared and settled based on bids from willing buyers 

and sellers. Instead, ISOs auction off FTRs and then pay off these 

FTRs using congestion revenues that would otherwise be refunded 

to transmission ratepayers. 

Unfortunately, the revenues collected from the auctioned FTRs 

consistently are much lower than what ISOs pay out. This makes 

FTRs highly profitable for financial entities, but these profits directly reduce congestion revenues refunded back to ratepayers. We 

estimate ISO ratepayers nationwide are losing at least $400 million 

per year from FTRs sold at auction. Almost all of these profits are 

going to purely financial entities and trading companies with a 

very small portion of FTRs purchased as potential hedges against 

congestion costs. 

In California, ratepayers lost over $680 million since 2009 or 

about $75 million a year through the auction. Ratepayers receive 

only 52 cents in the auction for each dollar that the ISO pays out 

to these FTRs. This represents a profit of nearly a hundred percent 

for financial entities purchasing these FTRs. 

24 

In the PJM Interconnection, data indicated ratepayers have lost 

at least $1.2 billion in FTR auctions, or about $170 million per 

year. As a result, PJM’s independent market monitor and the Organization of PJM States are calling for changes to PJM’s FTR 

process to ensure all congestion revenues are refunded to ratepayers. 

In New York, recent analysis by Stanford University shows that 

non-load-serving entities received FTR profits of over 900 million 

since 1999, or about $60 million per year. As explained in a 2014 

expose in the New York Times, FTRs were originally designed to 

help protect electricity producers, utilities, and industries that need 

to buy power, but, quote, Wall Street banks and other investors 

have stepped in, siphoning off much of the money. 

In the Midwest ISO, ratepayers have received less than 80 percent of day-ahead congestion rent since 2010. This represents a loss 

of at least a hundred million dollars per year from the FTR auction. If ISOs don’t take action to address this issue, the FERC will 

need to take action to protect the Nation’s transmission ratepayers. 

Thank you again for the opportunity to be here today and I look 

forward to answering any questions you have on this issue. 

[The prepared statement of Dr. Hildebrandt follows:] 

25 


Summary of Testimony of Eric Hildebrandt, PhD 

Director, Department of Market Monitoring 

California Independent System Operator Corporation 

Ratepayers of load serving utilities pay for the full cost of the transmission 

system through Transmission Access Charges- and also through higher prices when 

congestion occurs. All congestion revenues collected by ISOs from use of the 

transmission system should therefore be allocated back to transmission ratepayers. 

However, all !SO's auction financial instruments commonly called Financial 

Transmission Rights ("FTRs"). Revenues collected from auctioned FTRs are 

consistently much lower that what the ISOs pay out to entities purchasing these FTRs. 

This directly reduces the congestion revenues that would otherwise be refunded back to 

transmission ratepayers. 

Based on data reported by ISOs, we estimate transmission ratepayers 

nationwide are losing over $400 million per year from auctioned FTRs. Almost all 

profits from auctioned FTRs are going to purely financial entities and trading companies 

-with a very small portion of FTRs purchased by electric generators as potential 

hedges against congestion costs. ISOs do not need to auction FTRs for electricity 

suppliers to gain access to physical transmission or to hedge price risks associated with 

wholesale energy contracts and trading. If policy makers believe ISO's should facilitate 

financial hedging, !SO's should do this through a market for FTRs that is cleared and 

settled based on bids and offers from willing buyers and sellers. Transmission 

ratepayers should not be exposed to the losses and risks that they are currently 

suffering as a result of FTR auctions being run by ISOs. 
26 


Testimony of Eric Hildebrandt, Ph.D. 

Director, Department of Market Monitoring 

California Independent System Operator Corporation 

Committee on Energy and Commerce 

Subcommittee on Energy 

United States House of Representatives 

November 29, 2017 

My name is Eric Hildebrandt. I am the Director of Market Monitoring at the 

California Independent System Operator (ISO). The Department of Market Monitoring 

serves as the independent market monitor for the California ISO. Under FERC 

regulations, each Commission-approved ISO must have an independent market 

monitor, whose mission includes "the protection of consumers and market participants 

by the identification and reporting of market design flaws and market power abuses." 1 

My testimony today focuses on a major market design flaw that exists in all 

FERC jurisdictionaiiSOs which is costing transmission ratepayers over $400 million 

each year. This flaw involves the auctioning of purely financial instruments most 

commonly called Financial Transmission Rights ("FTRs"). The California ISO calls 

these Congestion Revenue Rights (or "CRRs"). 

Ratepayers of load serving utilities pay for the full cost of the transmission 

system through Transmission Access Charges- and also through higher prices when 

congestion occurs. All congestion revenues collected by ISOs should therefore be 

allocated back to transmission ratepayers. In fact, FTRs were initially developed as a 

1 Final Rule, Order No. 719 (Issued October 17, 2008) §35.28 Part 35 3(i) (f) P.314. 

https:/lwww.ferc.gov/whats-new/comm-meet/2008/1 01608/E-1.pdf 

1 
27 


way to fairly allocate congestion revenues back to participants who pay for the 

transmission system. 

AIIISOs currently allocate FTRs to load serving entities based on their projected 

use of the transmission system. We support continued use of FTRs in this way as a 

means for providing load serving entities with a hedge that offsets congestion charges 

they incur. In addition, all of the additional congestion revenues that remain after 

settlement of these allocated FTRs should also be refunded to transmission ratepayers. 

However, after allocating FTRs to load serving entities, aiiiSOs then auction off 

additional FTRs. These financial instruments are essentially price swap contracts. But 

unlike price swaps for other commodities, FTRs sold in the ISO auction are not cleared 

and settled based on bids from willing buyers and sellers. Instead, ISOs auction off 

FTRs --and then paid off these FTRs using congestion revenues that would otherwise 

be refunded to transmission ratepayers. 

Unfortunately, revenues that ISOs collect from auctioned FTRs are consistently 

much lower that what the ISOs pay out to entities purchasing these FTRs. This makes 

FTRs highly profitable for financial entities, but these profits directly reduce the 

congestion revenues that would otherwise be refunded back to transmission ratepayers. 

Based on data reported by ISOs, we estimate transmission ratepayers 

nationwide are losing over $400 million per year from FTRs sold at auction in various 

ISOs. Almost all of these profits are going to purely financial entities and trading 

companies- with a very small portion of FTRs purchased by electric generators as 

potential hedges against congestion costs. 

2 
28 


In the California ISO, ratepayers have lost over $680 million since 2009- or 

about $75 million per year. Transmission ratepayers receive only 52 cents in auction 

revenues for each dollar the ISO pays out to these FTRs. That represents a profit of 

nearly 100 percent for entities purchasing these FTRs. 

In the PJM Interconnection, data indicate that transmission ratepayers have lost 

about $1.2 billion in FTR auctions to financial entities since 2011 or about $170 million 

per year. 2 As a result, PJM's independent market monitor and the Organization of PJM 

States have called for changes to PJM's FTR process to ensure all congestion 

revenues are returned to load serving entities.' 

In the New York ISO, recent analysis at Stanford University shows that non-load 

serving entities received FTR profits over $900 million since 1999 - or about $60 million 

per year. 4 As explained in a 2014 expose in the New York Times, FTRs were originally 

designed to help "protect the electricity producers, utilities and industries that need to 

buy power'' by helping them "hedge against sharp price swings .... but Wall Street 

2 Monitoring Analytics, 2016 State of the Market Report for PJM p. 553: 

http://www.monitoringanalytics.comlreportsiPJM State of the Markel/201612016-som-pjm-sec13.pdf 

Monitoring Analytics, 2017 Quarterly State of the Market Report for PJM: January through December p. 

599: http://www.moniloringanalvtics.comlreports/PJM State of the Markel/201712017g3-som-pjmsec13.pdf 

3 Organization of PJM States, Inc (OPSI), OPS/ Resolution 2016-4 Concerning Financial Transmission 

Rights, Approved August 18, 2016. https://www.pjm.comHmedia/about-pjm/who-we-are/publicdisclosures/20160826-opsi-letter-and-resolution-regarding-ftr-construct.ashx 

4 Leslie, Gordon, "Why do transmission congestion contract auctions cost ratepayers money? Evidence 

from New York," November 14, 2017, pp. 23-24, downloaded 11/17/2017: 

http://www.web.stanford.edu/-gwleslie/index new files/Leslie JMP20171114.pdf. 

3 
29 


banks and other investors have stepped in, siphoning off much of the money," 

according to the Times. 5 

In the Midwest ISO, transmission ratepayers have received less than 80 percent 

of day-ahead congestion rent, representing a loss of at least $100 million per year from 

the MISO's FTR auction. 6 

ISOs do not need to auction FTRs for generation owners or energy traders to 

gain access to physical transmission or to hedge price risks associated with wholesale 

energy contracts and trading. As with other commodities, market participants and 

financial entities are free to develop and trade price swap contracts. In fact, this type of 

free market with trades between willing buyers and sellers - is what is needed to price 

such price swaps most efficiently and fairly. 

If policy makers believe it is beneficial to wholesale electricity markets and 

consumers for !SO's to facilitate such financial price swaps, then !SO's should do this 

through a market for FTRs that is cleared and settled based on bids and offers from 

willing buyers and sellers. 

Transmission ratepayers should not be exposed to the losses and risks that they 

are currently suffering as a result of FTR auctions being run by ISOs. If ISOs do not 

5 "Traders Profit as Power Grid is Overworked" The New York Times August 14, 2014: 

https:l/www. nytimes. com/20 14/08/15/business/energy-environment/lraders-profit-as-power -orid-isoverworked.html 

6 Problems in the performance and design of the congestion revenue right auction, Department of Market 

Monitoring, California Independent System Operator, November 27, 2017, pp. 18-19. 

http://www.caiso.com/Documents/DMMWhitePaperProblems Performance Design CongestionRevenueRightAuction-Nov27 2017.pdf 

4 
30 


take action to address this issue, FERC will need to take action to protect the nation's 

transmission ratepayers. 

Additional details of our analysis, along with a detailed discussion of the 

fundamental economic flaws underlying the auctioning of FTRs, are provided in an 

attached report by the California ISO Department of Market Monitoring. 7 Another report 

posted on our website provides a discussion of market-based options through which 

energy generators, traders and financial entities can buy and sell financial instruments 

that allow hedging of congestion costs. 8 

Thank you for the opportunity to appear before you today. I look forward to 

answering your questions on this important issue. 

7 Problems in the performance and design of the congestion revenue right auction, Department of Market 

Monitoring, California Independent System Operator, November 27, 2017. 

http://www.caiso.com/Documents/DMMWhitePaperProblems Performance Design CongestionRevenueRightAuction-Nov27 2017.pdf 

8 Market alternatives to the congestion revenue rights auction, Department of Market Monitoring, 

California Independent System Operator, November 27, 2017. 

http://www.caiso.com/Documents/Market Alternatives CongestionRevenueRightsAuctionNov27 2017.pdf 

5 
31 


California Independent System Operator Corporation 

California ISO 

Problems in the performance and design 

of the congestion revenue right auction 

November 27,.2017 

Department of Market Monitoring 
32 


Department of Market Monitoring- California !SO November 2017 

TABLE OF CONTENTS 

Summary ..................................................................................................................................... l 

1 CRRs are financial forward contracts .................................................................................... s 

2 CRR auction results ........................................................................................................... 11 

3 Market barriers and flaws in CRR auction design ................................................................ 21 

4 Alternatives to the CRR auction ......................................................................................... 27 
33 


Department of Market Monitoring- California 150 November 2017 

Summary 

In markets based on locational marginal pricing, binding transmission constraints cause locational prices 

to differ. Prices are higher in areas where transmission limits constrain the ability of lower cost 

generation to meet demand and higher cost generation must be used. Prices are lower in areas where 

transmission limits constrain the market from using otherwise available lower cost generation. These 

price differences cause the total amount paid by buyers to exceed the amount paid to suppliers over the 

entire system. This creates a source of revenue known as congestion rent since it results from higher 

prices reflecting congestion on transmission constraints. 

Most congestion rents are allocated back to transmission ratepayers because they pay for most of the 

transmission system through the transmission access charge (TAC). The TAC is collected based on each 

participant's demand (i.e. load or exports). The TAC is set at a fixed rate ($/MWh) designed to cover the 

full capital costs and rate of return for transmission assets. Any revenues collected above the level 

required to cover these transmission costs, such as congestion rent, should therefore be refunded to the 

TAC ratepayers. 

Allocated CRRs are part of a system that distributes congestion rent to load serving entities on behalf of 

retail ratepayers and to other TAC ratepayers. This paper does not concern the congestion rent 

allocation or propose any changes to the current CRR allocation process. 

Auctioned CRRs, on the other hand, are purely financial instruments that obligate the !SO's transmission 

ratepayers to pay entities purchasing these CRRs the difference in day-ahead market prices between 

two locations. An auctioned CRR is a forward price swap. Payments in the auction are exchanged for 

payments based on differences in day-ahead market prices. 

California ISO transmission ratepayers lost over $680 million in the congestion revenue right (CRR) 

auction from 2009 through 2017. For every dollar ratepayers paid to entities purchasing CRRs in the 

auction, ratepayers received only 52 cents in auction revenues. This consistent underpricing of CRRs 

calls into question a fundamental assumption of the CRR auction design that competition will drive 

auction prices to equal the CRR's expected value. 

As described in this paper, the CRR auction differs from a competitive market-and other forward 

financial markets-in several ways. These differences create opportunities for purely financial entities 

to purchase CRRs at prices systematically lower than the payments that ratepayers are obligated to pay 

the auction participants. DMM has recommended that the ISO takes steps to eliminate the current 

framework by which the ISO auctions CRRs, and consider if the ISO should instead play a role in 

facilitating trading of CRRs or similar price swaps between willing buyers and sellers through a market 

based only on bids and offers. 

Auctioned CRRs are not needed for transmission access or to ship power between nodes. An LMP 

market is a centrally cleared market. Power is sold or bought through the central market at the market 

price. Market participants do not ship power from one location to another. The LMP at each location is 

the appropriate market price for that location. A CRR is not needed to ship power between locations 

because power is not shipped between locations. 

A CRR is not a day-ahead market transmission right. All day-ahead market bidders have access to the 

transmission system regardless of whether or not they hold a CRR. Instead, an auctioned CRR is simply a 

CAISO/DMM 
34 


Department of Market Monitoring- California ISO November 2017 

forward contract. This forward contract allows auction participants to hedge financial exposure to-or 

speculate on-uncertain day-ahead price differences between two locations. 

The demand for a financial hedge against day-ahead market locational price differences primarily comes 

from forward contracts that settle on pre-agreed upon reference power prices in the spot market. This 

forward contracting takes place outside the ISO markets. A supplier may sell a forward power contract 

at a location different than its generator's location. When this occurs, the day-ahead price on which the 

forward contract settles will be different than the day-ahead price the generator receives for selling 

power into the day-ahead market. Different settlement locations cause the supplier to face an 

uncertain day-ahead price difference that will not be hedged by the forward power contract. To hedge 

this uncertainty, a supplier may be willing to buy a forward contract for the difference between the dayahead prices at the two locations. 

Financial forward contracts on locational price differences can be purchased in the CRR auction. Unlike 

most other forward contract markets, the CRR auction allows participants to take positions without a 

counterparty offering to take the opposite position. Market participants can buy forward contracts in 

the CRR auction without trading with a willing seller. This is because the auction makes the !SO's 

transmission ratepayers the counterparty to contracts bought from the CRR auction without being an 

explicit willing seller. 

CRR forward contracts are essentially price swaps offered for sale in the auction at offer prices of $0 by 

the ISO on behalf transmission ratepayers. To avoid being a counterparty to the forward contracts 

offered under the current CRR auction design, ratepayers would need to participate in the auction to 

buy contracts from themselves. This is the opposite of most other forward markets where sellers must 

willingly offer to enter a forward contract. 

While ratepayers may want to buy CRRs to avoid forward contract obligations, they cannot readily buy 

them. Technical, economic and regulatory hurdles restrict ratepayer participation in the auction. 

Ratepayers cannot easily avoid being a counterparty to the forward contracts they did not offer to 

enter. An auction participant can therefore buy a CRR from ratepayers for a price at which ratepayers 

would not willingly sell. 

The CRR auction also differs from other forward markets, and competitive markets generally, in another 

significant way. Competitive markets trade a well-defined product or property right. For example, a 

forward contract for a bushel of wheat is defined as a bushel of wheat in both the forward and spot 

markets. A natural gas forward basis contract between Henry Hub and Chicago is defined as the price 

difference between Henry Hub and Chicago in both the forward and spot markets. A CRR is not 

consistently defined between the auction and day-ahead market. 

CRRs are auctioned as a bundle of forward contracts on specific transmission constraints. However, 

CRRs are not settled as the same bundle of forward contracts at day-ahead market prices. Instead, the 

CRRs are settled at the day-ahead market locational price differences between two locations. A CRR will 

only be consistently defined if the bundle in the auction is the same as the implied bundle from the dayahead market price differences. When the transmission models are different in the auction and dayahead market, the bundles will not be the same. The CRR will be a different product when bought than 

when settled at day-ahead market prices. 

CRRs are unlikely to be consistently defined because the CRR auction relies on a single estimated 

network model to estimate a series of different hourly day-ahead network models that are ultimately 

used in the market over the entire settlement month or quarter. This settlement is like allowing auction 
35 


Department of Market Monitoring- California ISO November 2017 

participants to purchase premium gasoline at prices for regular gasoline with ratepayers making up the 

difference. Profit maximizing auction participants would bid to obtain CRRs that the auction models as 

being of a lower (regular) value but which they anticipate to be a higher value (premium) product. 

The peculiarities and complexities of the CRR auction can create opportunities for participants to 

routinely extract payments from ratepayers. The majority of these payments are from ratepayers to 

purely financial entities seeking to profit from participation in the auction, rather than suppliers that 

may be seeking to hedge risks related to day-ahead market schedules. 

There is no clear rationale for the ISO to offer forward price swaps. Market participants can freely 

contract and trade forward price swaps outside the ISO. If the ISO continues to facilitate the trading of 

forward price swaps, the auction design should be changed so that only willing counterparties will enter 

forward contract obligations. 
36 


Department of Market Monitoring- California ISO November 2017 

1 CRRs are financial forward contracts 

Ratepayers pay for and own most congestion rent 

Nodal markets are designed to promote efficient use of the scarce transmission system. The 

transmission system both facilitates and limits the ability to reliably trade energy. The limited 

transmission available in the day-ahead market constrains the choice of optimal energy schedules. This 

creates locational price differences which in turn creates congestion rent. 1 

Most congestion rents are allocated back to transmission ratepayers because they pay for most of the 

transmission system through the transmission access charge (TAC. 2 Ratepayers pay for the capital costs 

and rate of return on transmission assets through TAC that is imposed on all load schedules. Any 

revenues that these transmission assets earn in excess of the rate of return included in the TAC should 

therefore be credited or refunded to transmission the ratepayers. 

The ISO currently distributes congestion rent to the TAC ratepayers through an allocation process that 

includes the CRR allocation process. This allocation process is designed so that congestion rents are 

refunded back to different groups of transmission ratepayers in approximately the same proportion as 

these groups pay congestion. This paper does not concern the congestion rent allocation. Instead the 

focus of this paper is on the CRR auction. 

Network models define the transmission right products 

As described in the following subsections, auctioned CRRs are not rights to physical transmission, nor 

are auctioned CRRs even the rights to day-ahead market congestion rents. A CRR is a forward contract 

that is settled base on the difference in day-ahead market prices between two locations. Although a 

CRR settles on the day-ahead market congestion price differences, the ISO auctions CRRs as bundles of 

forward contracts to specific transmission constraints. Using the term congestion rights to refer to CRRs 

is inaccurate and misleading. In practice, congestions rents collected can be higher or lower than CRR 

payments, and payment of CRRS is made independent of congestion rents actually collected. Therefore, 

for the rest of this paper, we refer to CRRs as forward contracts. 

The CRR auction clears by maximizing total bid value constrained by the transmission network model. 

Forward contracts sold in the auction are defined by a network model, which includes specific nodes 

(locations), transmission constraints and shift factors. A shift factor describes how many forward 

contracts on a constraint are bought or sold from a one megawatt injection at a specific location. A CRR 

bids as an injection at a source location balanced by a withdrawal at a sink location. The forward 

contracts a CRR buys or sells on a particular constraint is the source shift factor minus the sink shift 

factor multiplied by the cleared CRR megawatts. The auction price for each increment of forward 

contract for that one constraint is the CRR auction's shadow price on the constraint. 

1 A good analogy is that transmission use is an externality of scheduling power and the transmission price is an externality tax, 

as explained on pg. 26 of Oren, Shmuel 5., Pablo T. Spiller, Pravin Varaiya, and Felix Wu. 1995. "Nodal Prices and Transmission 

Rights: A Critical AppraisaL" Electricity Journal,p. 32: http://www.ieor.berkeley.edu/""oren/pubs/nodal.pdf. 

2 Exceptions to this are rights owned by merchant transmission and long~term rights holders. However, these are very minor in 

the CAISO system. 

CAISO/DMM 
37 


Department of Market Monitoring- California ISO November 2017 

If a CRR's net shift factor (source shift factor minus sink shift factor) is positive, the CRR purchases 

forward contracts for the constraint's price. If a CRR's net shift factor is negative, the CRR sells forward 

contracts. The total forward contracts purchased by participants bidding in the auction do not need to 

equal the forward contracts sold by participants bidding into the auction. Instead, the forward contracts 

bought minus the forward contracts sold must be less than the forward contracts made available in the 

auction through each constraint's transmission limit. 

Equation 1 shows a CRR auction transmission constraint called k. Individual CRRs are indexed by i. 

Equation 1. CRR market constraints define forward contracts auctioned 

L MWcRR(ShiftFactor ~source- ShiftFactortsink) :$ Limitk 

i 

Contracts Bought - Contracts Sold ::; Contracts offered by auction 

Auction participants can buy more forward contracts than are sold by other participants bidding in the 

CRR auction. More forward contracts can be bought than sold because the ISO makes forward contracts 

available through its auction's transmission model. The ISO sells these forward contracts on behalf of 

transmission ratepayers. The CRR buyers pay ratepayers the auction revenues. The ratepayers then pay 

the buyers the day-ahead prices for these forward contracts. The ISO offers forward contracts on the 

ratepayers' behalf (through the limits on transmission elements in the CRR auction) with zero offer 

prices. 

CRRs are considered revenue adequate when revenues from congestion rents are greater than or equal 

to the payments to CRRs. CRRs will be revenue adequate if the transmission limits and network models 

(shift factors) are the same3 in both the auction and day-ahead market.• When the auction limits or 

network models are different, the CRRs may not be revenue adequate. 

Revenue adequacy is not a concern in forward markets for other commodities. 5 In forward markets for 

other commodities buyers and sellers are matched and revenue adequacy is assured. Revenue 

adequacy does not matter for CRRs either. Revenue adequacy does not matter because the CRR auction 

actually does match buyers and sellers. Ratepayers will always be the counterparties to contracts not 

matched between the buyers and willing sellers who bid into the auction. 

As discussed in detail in the next three sub-sections, CRRs can be better understood by interpreting 

CRRs from the perspective of the transactions between the buyers and sellers of CRRs, rather than from 

the perspective of revenue adequacy. The underlying transactions are the exchange of a fixed payment 

in the auction for floating payments at the uncertain day-ahead market prices. The transactions that 

matter to ratepayers are the auction revenues they receive compared to the payments they are 

obligated to make to CRR holders. 

3 More precisely, the difference between shift factors has to be the same between all locations. 

4 Hogan, William W. 1992. "Contract Networks for Electric Power Transmission.'~ Journal of Regulatory Economics. See the 

version at: http://www.hks.harvard.edu/fs/whogan/acnetref.pdf. 

5 This assumes away default risk, which is different than the revenue adequacy referred to here. 

CAISO/DMM 
38 


Department of Market Monitoring- California ISO November 2017 

Accounting for ratepayer gains or losses from CRRs sold in the auction 

The congestion revenue rights balancing account is a settlement mechanism. This settlement 

mechanism ensures that the final net payments and charges to the day-ahead market and to CRR 

auction participants are correct. The CRR balancing account processes two underlying transaction types. 

To understand the actual day-ahead market and CRR auction trades, we should consider the underlying 

transactions, rather than the net sum of the CRR balancing account. 

Figure 1 shows the two transaction types from the ratepayer's perspective. In the first type of 

transaction (box A), entities with energy schedules clearing the day-ahead market pay congestion rents. 

As discussed, transmission ratepayers should receive these congestion rents since they have paid for the 

transmission system through the TAC. Therefore, the ISO distributes some of the congestion rents to 

transmission ratepayers by CRRS allocated to load serving entities (box B). Any congestion rents 

remaining after the allocation process are distributed to participants who pay the TAC based on their 

pro-rata share of demand schedules, i.e. loads and exports (box C). Load serving entities, who are the 

largest transmission ratepayers, then pass the congestion rents back to transmission ratepayers. 

In the second type of transaction (shown in boxes D and E), CRR auction participants and ratepayers 

(who do not participate in the auction) trade financial forward contracts through auctioned CRRs. 

Auction participants pay the forward price (the auction price) to ratepayers (box D). In exchange, 

ratepayers take on the obligation to pay the spot price (the difference between the source and sink dayahead market prices) to auction participants (box E). The exchange of forward CRR auction revenues for 

spot market payments to auctioned CRRs at day-ahead market prices is the ratepayers' overall net 

forward contract trade. 

Figure 1. Different transaction types settled through the CRR balancing account 

Energy market load serving entities 

payingTAC 
39 


Department of Market Monitoring -California ISO November 2017 

If no CRRs were sold at auction, all remaining congestion revenues after payments made to allocated 

CRRs would be refunded to ratepayers of load serving entities who pay the TAC based on their pro-rata 

share of demand (box C). Thus, whenever auction revenues are less than payments made by the ISO to 

CRRs, the difference is a direct loss for transmission ratepayers. 

Congestion revenue rights are not actually rights to congestion rents 

When the CRR auction transmission model and day-ahead market transmission model are the same, we 

can view a CRR as a forward contract, a point-to-point transmission right, or a right to a share of 

congestion rent. 6 All three views are financially equivalent. 

However, the CRR auction and day-ahead market transmission models are inevitably different. When 

the models are different, paying CRRs the day-ahead market settlement price is not the same as paying 

a share of the congestion rent. For example, if 100 MWs of transmission is sold to entities with 

schedules clearing the day-ahead market, the ISO cannot pay CRRs for rights to 115 megawatts worth of 

congestion rent. The CRRs clearly do not represent the rights to the congestion rents. Instead, 

ratepayers receive the congestion rents for the 100 megawatts of transmission sold to day-ahead 

market schedules (see Transaction 1 in Figure 1). Separately, ratepayers must pay day-ahead market 

locational price differences to settle the 115 megawatts of CRR forward contracts that the ISO auctioned 

off on the ratepayers' behalf (see Transaction 2 in Figure 1). 

Even if the transmission models are the same, the CRR contracts sold for a constraint can be greater 

than the transmission limit because auction participants can sell additional forward contracts. If the 

constraint limit is 10 MWs and some participants sell an additional 50 MWs of forward contracts 

through CRR bids, a total of 60 MWs of forward contracts can be purchased by other CRR auction 

participants. 60 MWs of rights to congestion rent do not exist. The ISO does not arbitrarily decide that 

a particular 10 MWs of CRRs is rights to congestion while the other 50 are something else. Instead, all 

60 MWs are forward contract purchases with 50 MWs sold by parties bidding into the auction and 10 

MWs sold on behalf of transmission ratepayers. 

CRR profitability is the relevant measure of CRR auction performance 

CRR revenue inadequacy has traditionally received a lot of attention. Concerns over whether there will 

be sufficient congestion rent to pay the CRRs are rooted in the prevalent and incorrect view that CRRs 

are rights to the day-ahead market congestion rent. But once we recognize that CRRs are simply 

forward contracts, and not rights to congestion rent, it becomes clearer that focusing on revenue 

adequacy incorrectly frames the problem as a need for the ISO to make the "correct" amount of forward 

contracts available in the auction on behalf of ratepayers. 

The relevant question for ratepayers is not how total payments to CRRs compare to total day-ahead 

congestion rent (i.e. it is not a question of revenue adequacy). The relevant question for ratepayers is 

how the payments ratepayers are obligated to make to auctioned CRR holders compare to the CRR 

auction revenues ratepayers receive. If ratepayers pay auctioned CRR holders more than the auction 

revenues ratepayers receive, then ratepayers will lose money on their CRR forward contracts. 

6 Harvey, Scott M, Wi!liam W Hogan, and Susan l Pope. 1997, Transmission Capacity Reservations and Transmission Congestion 

Contracts. Cambridge, MA: Harvard University, p. 62 of the version at: http:Uwww.hks.harvard.edu/fs/whoganftccoptr3.pdf. 

CAISO/DMM 
40 


Department of Market Monitoring- California ISO November 2017 

The auction revenues ratepayers receive depends on how well the CRR auction prices CRRs. A wellfunctioning competitive auction would price CRRs near their expected value. The CRR auction revenues 

ratepayers receive would roughly equal the ratepayers' expected payments to non-LSE CRR holders. 

The CRRs purchased from ratepayers by non-LSE auction participants would not be highly profitable. If 

the CRR auction is not a well-functioning competitive market, non-LSE auction participants can 

consistently profit from ratepayers' losses without driving up CRR auction prices. 

CAISO/DMM 
41 


Department of Market Monitoring- California ISO November 2017 

2 CRR auction results 

The section provides analysis of the ISO's CRR auction since 2009. The section also provides a review of 

analysis and studies that have been performed for other I SO's. This analysis shows that auction 

revenues have been systematically much lower than CRR payments made to non-load serving entities. 

These results are not consistent with a well-functioning competitive market. Data from other ISO's 

indicate that these trends occur in other ISO's as well. 

CRRs are auctioned for only half the value of CRR payments 

As shown in Figure 2, ratepayers have consistently lost money in the CRR auction each year since the 

ISO's LMP market began in 2009. Ratepayers have lost over $680 million from the CRR auction from 

2009 through 2017, or an average of $75 million per year. Ratepayers paid over $1.4 billion to non-LSE 

CRR holders but received only $742 million in auction revenues. For every dollar paid to non-LSE CRR 

holders, ratepayers received just 52 cents. This represents more than a 90 percent annual rate of return 

for non-LSE entities purchasing CRRs in the auction. This clearly reflects a systematic bias and distortion 

in the CRR auction. 

$500 

$450 

$400 

$350 

~ $300 

'j'i $250 <I> 

$200 

$150 

$100 

$50 

$0 

Figure 2. Auction revenues and auctioned CRR payments excluding LSEs 

100% 

90% 

80% 

70% 

60% 

50% 

40% 

30% 

20% 

10% 

0% 

~ 

~ 

" E "

> 

"' Q. 

'C 

"' c 

0 

tJ 

" 

-

"' 0 

~ 

::: " 

lii 

0.. 

As shown in Table 1, most profits from CRRS purchased in the auction go to financial entities that do not 

operate or schedule physical generation assets in the ISO system -and do not purchase CRRS to hedge 

power contracts. Since 2009, non-LSEs and non-physical generation entities (financial entities and 

marketers} received about $598 million in profits from the CRR auction, paying 52 cents per dollar 

11 
42 


Department of Market Monitoring- California ISO November 2017 

received representing a profit of almost 100 percent. Physical generators received $86 in profits 

paying 45 cents per dollar. 

Table 1. CRR auction profits{$ millions)- Physical generators 

Veil\" Audion 

Revenui!S 

CIIR 

J>ayments 

Profits 

2009 $2 $2 $0 

2010 $0 $1 $1 

2011 $3 $4 

2012 $9 $25 $16 

2013 $14 $31 $16 

2014 $14 $48 $34 

2015 $17 $24 $7 

2016 $9 $14 $5 

2017* 

Total $11 $157 $86 

•2017 is year·to·date through October 31. 

Table 2. CRR auction profits ($ millions) Financial traders and marketers 

(excludes load serving entities and physical generators) 

Year Auction CIIR Profits Rmooes Payments 

2009 $24 $43 $19 

2010 $45 $46 $0 

2011 $35 $78 $43 

2012 $64 $200 $136 

2013 $110 $201 $91 

2014 $115 $297 $182 

2015 $109 $148 $39 

2016 $91 $133 $43 

2017. 

Total $671 $1,269 $598 

•2017 is year·t~date through October 31. 

12 
43 


Department of Market Monitoring- California ISO November 2017 

Figure 3 provides a more detailed analysis of how CRRs have been consistently profitable over time for 

virtually all non-TAC ratepayer (non-LSE) CRR auction participants. Figure 3 shows the distribution of 

total annual profits and losses for all annual portfolios of CRRs purchased by non-LSEs over the 2009 

through Q3 2017 period. These data illustrate that the portfolios of CRRs purchased by different nonLSEs in the auction were systematically profitable and extremely skewed, with very limited risk of 

potentia I losses. 

Over the 2009 through Q3 2017 period shown in Figure 3, non-LSE portfolios that were profitable were 

paid about $728 million dollars. Non-LSE portfolios that were not profitable lost only about $50 million. 

The losses were about 7% the amount of gains. This is not indicative of a well-functioning market. The 

$677 million difference in profitable versus unprofitable CRR portfolios purchased in the auction was 

paid from revenue that would otherwise have been refunded to transmission ratepayers to partially 

offset TAC payments charged to load serving entities. 

Figure 3. Annual profits on auctioned CRRs by entity (excluding LSEsj2009-Q3, 2017 

$40 

$35 

$30 

"' ~ $25 

·e 

e $20 

.. "' E $15 

~ 

:: $10 

z "' 

$5 

$0 

($5) 

Portfolio-quarter 

Start of portfolio-years 

with annual losses 

Figures 4 through 6 summarizes a more detailed analysis of how systematically profitable portfolios of 

CRRs purchased in the auction have been for different types on non-LSEs. These figures compare the 

amount paid by individual participants for portfolios of monthly and seasonal CRRs each quarter to the 

revenues received for these portfolios. Observations below the 45 degree line are quarterly CRR 

portfolios that were profitable. Observations above the 45 degree line are quarterly portfolios that 

were unprofitable. 7 

7 These charts also show CRR portfolio data from Ql 2014 through Q2 2017 calculated on a quarterly basis corresponding to the 

term of seasonal CRRs (rather than on a monthly basis), 

CAISO/DMM 13 
44 


Department of Market Monitoring- California lSO November 2017 

Figure 4. All non-load serving entities' quarterly auction revenues versus CRR payments by portfolio 

(2014-Q2 2017) 

$35 

$30 

]' $25 

~ $20 

~ $15 

~ $10 

u 

~ $5 

3! $0 

~ ($5) 

"' g ($10) 

"' 11; ($15) 

" "' ($20) .2 

t1 ($25) 

<>: "' ($30) 

($35) 

"""''"'''''"" 45 degree line 

Generator 

0 Marketer 

finan-cial 

Payments to CilRs {$ mil!ion) 

Figure 5. Financial entities' quarterly auction revenues versus CRR payments by portfolio, 2014 to Q2 

2017 (axes truncated at $10 million) 

"E' 

~ ·s 

~ 

<2 

" u 

~ 

3! 

&. 

"' "' "' 

~ "' 

&! 

c 

,Q 

ti 

~ 

$10 

$8 

$6 

degree 

Financial 

Payments to CRRs ($ million) 

14 
45 


Department of Market Monltoring-Californla ISO November 2017 

Figure 6. Marketers' quarterly auction revenues versus CRR payments by portfolio 

(2014 to Q2 2017- axes truncated at $10 million) 

$10 

" $8 g $6 'E 

~ $4 

~ u $2 

E 

3! $0 

~ 

iil ($2) 

il 

~ ($4) 

.!:! ($6) 

tl 

~ ($8) 

($10) 

o Marketer 

0 

Payments to CRRs {$ mllllon) 

Figure 7. Generators' quarterly auction revenues versus CRR payments by portfolio, 2014·Q2 2017 

(axes truncated at $10 million) 

$10 

~ $4 

02 

5 $2 

E 

;g $0 

ll. 

"' "' 2l 

!!! {$4) 

£ 

.§ ($6) 

tl 

~ ($8) 

($10) 

--45 degree line 

Generator 

Payments !o CRRs {$ million) 

15 
46 


Department of Market Monitoring- California ISO November 2017 

The risk and time value of money associated with CRRS does not explain 

abnormally high profits 

Auction participants may be risk adverse. Risk aversion may cause the CRR auction prices to not equal 

the expected day-ahead payments. Auction participants may be increasing or decreasing their risk by 

procuring a CRR. Participants increasing their risk would be willing to pay less than the expected value. 

Participants decreasing their risk would be willing to pay more than the expected value as an insurance 

premium. Therefore we cannot presume that risk aversion will decrease or increase auction prices 

relative to the expected value. 

This analysis does not discount the auction revenue and CRR payment flows for the time value of 

money. However, most of the monthly CRR payments occur less than a month after purchase. Only the 

payments to annual CRRs in late November and December occur more than a year after the CRRs are 

purchased. Given the short time periods, discounting the cash flows would not appreciably affect the 

values. The effects of risk aversion and the time value of money cannot account for pricing CRR's sold in 

the auction at only 53 cents for each dollar of congestion payments. 

Ratepayers losses occur from CRRIFTR auctions in other ISOs!RTOs 

The California ISO is not the only 150/RTO where transmission ratepayers have been losing money in 

auctions for Financial Transmission Rights (the term for CRRs in these markets). 8 Data reported by 

different ISOs/RTOs is not always reported in a manner that clearly shows the impact of these auctions 

on transmission ratepayers. However, there are clear indications FTR auctions are highly profitable for 

the auction participants in multiple markets. Based on DMM's review, auctions clearly result in losses of 

several hundred millions dollars per year nationwide. A 2017 analysis at Stanford University estimates 

that losses to ratepayers total about $600 million per year in the countries four main ISOs. 9 

PJM 

In the PJM Interconnection (PJM), data reported by PJM's Independent Market Monitor indicate that 

transmission ratepayers have lost over $1.18 billion in FTR auctions from 2011 to September 2017. 

Financial entities have received about $170 million per year in FTR profits (see Table 3). 10 As noted by 

PJM's Independent Market Monitor: 

In an LMP system, the only way to ensure that load receives the benefits associated with the use of 

the transmission system to deliver low cost energy is to use FTRs to pay back to load the difference 

between the total load payments and the total generation revenues, which equals total congestion 

revenues. 

8 CRRs in other ISOs/RTOs are also known as financial transmission rights (FTRs}, transmission congestion contracts (TCCs), and 

transmission congestion rights (TCRs}. 

9 "Traders Profit as Power Grid is Overworked" The New York Times August 14, 2014: 

https://www.nvtlmes.com/2014/08/15/business/energy~environment/traders~profit-as-power-grid-is-overworked.html 

10 Monitoring Analytics, 2016 State of the Market Report for PJM p. 553: 

http://www.monitoringanalvtics.com/reports/PJM State of the Market/2016/2016-som-pjm-secB.pdf 

Monitoring Analytics, 2017 Quarterly State of the Market Report for PJM: January through December p. 599: 

http://www.monitoringanalytics.com/reports/PJM State of the Market/2017/2017g3-som-pim-sec13.pdf 
47 


Department of Market Monitoring- California !SO November 2017 

PJM's Market Monitor has recommended changes to PJM's FTR process to ensure all congestion 

revenues are returned to load serving entities, noting that: 

The current ARR/FTR design does not serve as an efficient way to ensure that load receives all the 

congestion revenues or has the ability to receive the auction revenues associated with all the 

potential congestion revenues. 

In 2016, the Organization of PJM States (OPSI) passed a resolution citing the PJM Market Monitors 

findings and recommendations calling upon PJM to propose a redesign of the PJM's FTR market "that 

will ensure that all congestion revenues are returned to consumers." 11 As noted in the OPSI resolution, 

"[c]onsumers pay for all congestion in the system, so anything short of the prospect for realizing a full 

return of those congestion revenues [to consumers] would indicate a failure in achieving the objective of 

the ARR/FTR construct." 

Table 3. PJM financial entity FTR auction profits($ millions) 

Year financial Entity 

Profits 

2011 $126 

2012 $79 

2013 $177 

2014 $544 

2015 $182 

2016 $48 

*2017 ytd thru September. 

NYISO 

In 2014 the New York Times reported on the very large FTR auction profits in the New York ISO (NYS0}. 12 

As explained in the Times article, FTRs were originally designed to help "protect the electricity 

producers, utilities and industries that need to buy power," by helping them "hedge against sharp price 

swings caused by competition as well as the weather, plant failures or equipment problems." Those 

lower costs reduce consumers' bills, "but Wall Street banks and other investors have stepped in, 

siphoning off much of the money". 

The New York Times article provides valuable insights into the barriers to competition in what it calls a 

"murky corner" of the energy market. 

like top Wall Street banks, DC Energy [a major financial trader of FTRs] stocks its trading desk with 

graduates of elite universities. Most have backgrounds in science and engineering- a doctorate in 

chemical physics from Harvard, for example, or a master's degree in artificial intelligence from 

11 Organization of PJM States, Inc (OPSI), OPSI Resolution 2016-4 Concerning Financial Transmission Rights, Approved August 

18, 2016. https://www.pjm.com/"' /media/about~pjm/who-we-are/pu blic-disdosures/20160826-oosi-letter-and-resolutionregarding-ftr-construct.ashx 

12 "Traders Profit as Power Grid is Overworked" The New York Times August 14, 2014: 

httos:ljwww.nytimes.com/2014/08/15/business/energywenvironment/traders-profit-as~power-grld-iswoverworked.html 

17 
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Department of Market Monitoring- California !SO November 2017 

Stanford - rather than in finance. Their job is to develop computer-driven trading models to predict 

what will happen to electricity prices in different parts of the nation. 

As explained in the New York Times: 

... in places like upstate New York or Long Island, the market is so small, and the participants for 

certain contracts so few, that knowledgeable traders can collect rich rewards. Frank A. Wolak, an 

economics professor at Stanford who studies commodities, said the congestion markets created 

perverse incentives because profits rise when grid congestion becomes worse. "If traders are 

making money, then consumers are paying more," Mr. Wolak said. "The money that these guys are 

making has to come from somewhere." 

A recent research paper from Stanford University estimates that that in the New York ISO non-retail 

(non-LSE) entities received FTR profits totaling $938 million over the 1999-2016 period, almost $60 

million per year. 13 As noted in this research: 

... these derivatives have proven controversial because financial traders have consistently earned 

trading profits of $600m a year from holding these derivatives across the four largest U.S. electricity 

markets. These products are typically issued via regular auctions, with payouts of the issued 

derivatives funded by ratepayers, who in turn receive the auction revenues ... financial traders 

typically purchase many derivatives in small quantities between locations that physical firms do not 

tend to buy. Financial traders earn profits when they are the first to buy a previously illiquid 

product, where they effectively receive a transfer from ratepayers for this service. 14 

MISO 

In the Midcontinent ISO (MISO) for the 2010-2011 through 2016-2017 planning periods, on average only 

about 80% of the day-ahead market congestion rent was received by transmission ratepayers. 15 As 

explained in earlier DMM reports, this implies that transmission ratepayer losses in the FTR auction 

were equal to about 20% of day-ahead congestion rents for the period. 16 Day-ahead congestion rent 

averaged about $790 million from 2011 through 2016. 17 This data indicates that transmission 

ratepayers in MISO have consistently suffered large losses from the FTR auctions, between $100 million 

and $200 million per year. 

13 Leslie, Gordon "Why do transmission congestion contract auctions cost ratepayers money? Evidence from New York" 

November 14,2017, pp23-24, downloaded 11/17/2017: 

http://www.web.stanford.edu/"'gwleslie/lndex new files/Leslie JMP20171114.pdf. 

14 1bid, p.1 

15 Midcontinent ISO ARR/FTR Transmission Customer Metric May 11, 2017: 

https:l/www.misoenergy.org/Library/Repository/Meeting%20Materjai/Stakeholder /MSC/2017/20170511/20170511%20MSC 

%201tem%20XX%20ARR%20FTR%20Transmission%20Customer%20Metric%20Aprii%202017%20Update.pdf 

16 Department of Market Monitoring Shortcomings in the Congestion Revenue Right Auction Design p.6: 

https://www.caiso.com/Documents/DMM-WhitePaper-Shortcomings~CongestionRevenueRightAuctionDesign.pdf 

17 MISO day-ahead congestion rent data from Potomac Economics 2016 State of the Market Report for the MISO Electricity 

Market p.SO; Potomac Economics 2014 State of the Market Report for the MISO Electricity Market p.S2; Potomac Economics 

2012 State of the Market Report for the MISO Electricity Market p.46. Reports available at: 

https://www.misoenergy.org/MARKETSOPERATIONS/INDEPENDENTMARKETMONITOR/Pages/lndependentMarketMonitor.as 

Pl! 

CAISO/DMM 18 
49 


Department of Market Monitoring- California ISO November 2017 

Table 4 shows the percent of day-ahead market congestion rent received by MISO ratepayers across the 

planning years since 2010. Table 4 also shows the annual day-ahead congestion rent by calendar year. 

We estimate losses to ratepayers from the auction multiplying the percentage of day-ahead congestion 

rent that was not returned to ratepayers each year by the reported congestion rent for that year. 

The planning period and calendar years used by the MISO are not align. Therefore, the range of auction 

losses is estimated first by multiplying the percentage of day-ahead congestion rent that was not 

returned to ratepayers by the congestion rent where the start year of the planning period and calendar 

year are the same. We also estimated auction losses based on congestion rents where the end year of 

planning period and calendar year are the same. These two approaches indicate a range of losses to 

MISO transmission ratepayers from FTRs sold in the auction of $165 million to $207 million. 

Table 4. MISO percent of day-ahead market congestion rent received by ratepayers and estimated 

potential range of ratepayer FTR auction losses($ millions) 

Percent<>f calendar Estimated Auction Losses Planning Annual DAM Rent Start Year End Year Period Year DAM Rent Returned Percent Percent 

06/10 05/11 72% 2010 $498 $139 

06/11- 05/12 75% 2011 $503 $126 $141 

06/12 05/13 79% 2012 $778 $163 $194 

06/13 - 05/14 64% 2013 $842 $303 $177 

06/14 05/15 89% 2014 $1,444 $159 $520 

06/15 -05/16 83% 2015 $751 $128 $83 
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Department of Market Monitoring- California !SO November 2017 

3 Market barriers and flaws in CRR auction design 

This section explains several factors that are likely to help explain the very poor performance of the CRR 

auction from the perspective of ratepayers. These include: 

CRRs are not consistently defined products in both the auction and day-ahead market. 

CRR auction participants can profit from better information on difference in the way CRRs are 

defined in the auction versus the day-ahead market- without increasing efficiency or adding any 

value to ratepayers or other market participants. 

Ratepayers face significant limitations to bidding in auctions 

Buyers do not have an incentive to bid auctioned CRRs up to their expected value 

These represent fundamental flaws that cannot be eliminated under the current market design. The last 

section of this paper discusses how these flaws could be addressed through a voluntary market for price 

swaps between willing buyers and sellers. However, this option should only be pursued if policymakers 

believe that the benefits of facilitating price swaps warrant or require intervention by the ISO, rather 

than allowing price swaps to occur through private mechanisms as occurs with other commodities. 

CRRs are not consistently defined products in both the auction and day-ahead 

market. 

In the monthly CRR auction, the ISO uses a transmission model developed at least several weeks, and as 

much as a month, prior to the relevant day-ahead market hour. The ISO conducts the seasonal CRR 

auctions at the end of the year prior to the settlement year. Many outages " ... cannot be known until 

real-time operations ... " and these outages can " ... change the system configuration and result in different 

shift factors ... " than used in the auction." Different limits and network configurations are possible and 

likely. "Therefore, it might be that the assignment [of CRRs] is not, in all circumstances and under all 

conditions, actually feasible." 19 

When CRRS are auctioned based on a network model that is not feasible given the model actually used 

in the day-ahead market, this can cause revenue inadequacy. However, the use of different network 

models in the CRR auction and day-ahead market creates a more basic issue than revenue inadequacy. 

Different models mean the CRR product is defined differently in the CRR auction than in the day-ahead 

market. A CRR holder buys a specific bundle of forward contracts in the auction. But the CRR holder can 

be paid the day-ahead prices for a different bundle of forward contracts. The product purchased in the 

CRR auction is not the same product settled in the day-ahead market. Because the day-ahead market 

network model is not and cannot be known when the auction is run, it is uncertain what transmission 

constraint prices the CRR will settle on in the day-ahead market. 

Consider a case where the ISO introduces a completely new constraint (Constraint A) into the day-ahead 

market. When Constraint A is binding in the day-ahead market, it increases payments to a CRR. When 

18 Bautista Alderete1 Guillermo. ''FTRs and Revenue Adequacy" in Financial Transmission Rights: Analysis. Experience and 

Prospects. Springer 2013. Edited by Juan Rose116n and Tarjei Kristiansen, p. 253. 

19 Harvey, Scott M, William W Hogan, and Susan L Pope. 1997. Transm;ssion Capacity Reservations and Transmiss;on Congestion 

Contracts. Cambridge, MA: Harvard University, p. 62 of the version at: http:Uwww.hks.harvard.edu/fs/whogan/tccootr3.pdf. 

21 
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Department of Market Monitoring- California ISO November 2017 

the ISO pays the CRR holder for the entire difference in day-ahead market congestion prices between 

the source and sink nodes, the ISO pays the CRR holder for a forward contract to the Constraint A which 

was not even modeled in the auction. The CRR holder is paid for this forward contract even though a 

forward contract to Constraint A was not purchased, or even offered, in the auction. 

Under this scenario the ISO does not explicitly offer a forward contract for Constraint A in the auction, 

yet a forward contract for congestion on Constraint A is actually available. The CRR will be settled on 

the entire day-ahead market source-sink price difference, which includes the day-ahead market 

transmission price for Constraint A. This CRR is a different bundle of forward contracts in the auction 

than it is in the day-ahead market. At the time the CRR auction is held, it is not clear what constraints 

will be enforced in the day-ahead market. Therefore, it is not clear what forward transmission right 

contracts are actually available in the CRR auction. 

Similar problems occur when the ISO models a constraint differently between the CRR auction and dayahead market. Consider a 100 megawatt CRR whose source and sink locations both have .10 shift 

factors to another transmission constraint (Constraint B). The holder of this CRR would purchase zero 

net megawatts of forward contracts to Constraint B. If in the day-ahead market model the sink shift 

factor to Constraint changes to 0.05, while the source shift factor remains .10, the CRR holder would be 

paid for 5 megawatts of forward contracts to Constraint Bat the day-ahead market price. Again the CRR 

holder never purchased forward contract for Constraint B. Different transmission models, as defined by 

different shift factors in the CRR model and day-ahead market model, can create the same or similar 

problems as non-modeled constraints. 

CRR auction participants profit from better information on modeling differences 

without adding any efficiency or value to the market 

Paying auctioned CRRs based on the full day-ahead market congestion price differences between the 

source and sink nodes is like allowing buyers to purchase regular gasoline now to sell at premium prices 

later. The network model in the auction is public information to the CRR auction participants. Auction 

participants can compare the public CRR auction model to their private estimates of the multiple 

network models over the month or season in which the auctioned CRRs will settle. An auction 

participant may find CRRs modeled in the auction as lower value, "regular," that the participant models 

as higher value, "premium." Profit maximizing participants will bid to obtain CRRs modeled in the 

auction as regular but which they anticipate to be premium. 

Similar use of superior private information to bid into auctions has been studied in construction 

contract, government procurement, timber, and online advertisement auctions. 20 These studies show 

that the use of superior private information in auctions with inconsistently defined products can result 

in decreased auction revenues relative to the value of the product actually being auctioned." 

20 As examples see: 

Athey, Susan, and Jonathan Levin. 2001. "Information and competition in US Forest Service timber auctions." Journal of 

Politico/ Economy: http://web.stanford.eduhdlevin/Papers/Skewing.pdf. 

Agarwal, Nikhil, Susan Athay, and David Yang. 2009. 11Skewed Bidding in Pay Per Action Auctions for Online Advertising" The 

American Economic Review: http://economics.mit.edu/files/10630. 

21 For procurement auctions it can result in increased payments to the auction participant relative to the value of the product 

or service procured. 

CAISO/DMM 22 
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Department of Market Monitoring- California ISO November 2017 

A simple example CRR auction illustrates how a CRR auction participant can profit from having better 

estimates of the actual day-ahead market shift factors. The example auction has one constraint 

(Constraint X) with a 10 MW limit. Table 4 shows the auction bids, auction shift factors, actual dayahead shift factors and actual day-ahead shadow value for Constraint X. Two auction participants 

(Company Y and Company Z) expect a $30/MW shadow value for Constraint X which equals the actual 

day-ahead market shadow price. 

Table 5. Example of CRR auction with shift factors different than day-ahead market 

DA 

CRR CRRBid Cleared Net Shift Factor Bid Price Per MW Mkt 

Nam CRR 

Bidder e Price MW MW Auction DAMkt Auction Actual s.v. 

CompanyY A-C $3.00 150 0 0.10 0.10 $30.00 $30.00 $30.00 

CompanyZ B-C $3.10 150 100 0.10 0.15 $31.00 $20.67 $30.00 

Company Y does not have better estimates of the day-ahead shift factors than the auction. Company Y 

wants a CRR between locations A and C, and bids the expected price difference between A and C of 

$3.00/MW. This equals the $30/MW value ofthe forward contract for Constraint X. 

Company Z has better estimates of the day-ahead market shift factors. Company Z expects the actual 

day-ahead market net shift factor difference between locations Band C will be .15 and not the .10 

modeled in the auction. Company Z bids $3.10/MW for CRRs between Band C. Company's bid appears 

to be $31/MW for forward contracts on Constraint X in the auction. Because $31/MW is greater than 

$30/MW Company Z is awarded alllO MW of forward contracts on Constraint X (100 CRR MWs 

multiplied by the .10 shift factor). Company B pays ratepayers $310 in auction revenues (10 MWs 

multiplied by $31/MW). 

But Company Z did not actually buy 10 MW of forward contracts on Constraint X. Because the actual 

net shift factor is .15, Company Z really bought 15 MW of forward contracts on Constraint X. Company 

Z's CRR is not a "regular" CRR with a 10 MW forward contract. Company Z's CRR is a "premium" CRR 

with a 15 MW forward contract. Ratepayers pay Company Z $450 in the day-ahead market (15 MW 

multiplied by the $30/MW day-ahead shadow value for Constraint X). Company Z's profits are $140 

($450 minus $310). Ratepayers lose $140 because they received $310 in auction revenues but paid 

Company Z $450 when settling the forward contract. 

Company Z actually bids only $20.67 /MW of Constraint X forward contracts ($310 divided by 15 MW). 

Company Z's bid appears to be $31/MW because the auction used the wrong shift factors and it 

appeared Company Z was only buying 10 MW. But Company Y is actually the highest bidder. Company 

Y's $30/MW bid is higher than Company Z's $20.67/MW bid. If the correct net shift factorfor Constraint 

X had been used, Company Y would have won all the Constraint X forward contracts in the auction. 

Because the CRR auction uses different shift factors than the day-ahead market, the actual highest 

bidder does not win the forward transmission right contracts in this example CRR auction. 

23 
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Department of Market Monitoring- California ISO November 2017 

Ratepayers face significant limitations to bidding in auctions 

The ISO determines the initial set of CRR forward contracts that ratepayers must offer at a $0 

reservation price through the transmission limits set by the ISO in the CRR auction. If ratepayers wanted 

to auction off less CRR forward contracts than the quantity implied by the auction's transmission limits, 

ratepayers would have to bid into the CRR auction to buy the forward contracts. Ratepayers could in 

theory set reserve prices for the CRR forward contracts. They could set reserve prices by submitting 

price sensitive demand bids to buy CRRs. However, ratepayers face significant limitations to transacting 

in the CRR auction. 

The costs for individual ratepayers to enter the auction obviously outweigh the benefits. load serving 

entities therefore participate in ISO markets on the ratepayers' behalf. But load serving entities do not 

have a direct monetary incentive to manage the ratepayers' CRR forward contracts in the auction. One 

reason for this is that load serving entities directly pass through to ratepayers any profits or losses from 

these CRRs that are passively auctioned off by the ISO on the ratepayers' behalf. 

load serving entities also face regulatory hurdles from managing these CRR forward contracts. For 

example, see the procurement plan passage below: 

As the Commission determined in Resolutions E-4135 and E-4122, [The LSE] uses CRRs and LTCRRs to hedge against congestion costs (expected and anticipated). [The lSE] does not use CRRs 

and lT-CRRs forfinancial speculation." 

The above passage reflects the prevalent misunderstanding of the current CRR auction design. Under 

the current CRR auction design, if load serving entities do not participate in the auction at all, ratepayers 

will be engaging in risky financial speculation. This is because running a CRR auction with non-zero 

transmission limits forces ratepayers to offer to sell risky CRR forward contracts at a $0 reservation 

price. 

Regulations such as those cited in the passage above result in load serving entities not being able to 

purchase CRR forward contracts at auction. As a result, load serving entities cannot use explicit CRR 

purchases to help ratepayers avoid being forced to sell risky CRR forward contracts. load serving 

entities can only bid for CRR forward contracts if they expect to use these CRR contracts to offset 

specific expected congestion costs as approved by the utility commission. load serving entity 

procurement plans contain similar passages for all three investor owned load serving entities in the 

150.23 

To purchase or set reserve prices on the CRR forward contracts offered by the ISO at $0 reservation 

prices, load serving entities would also need to determine what CRR forward contracts are actually being 

offered. As previously described, because CRRs are inconsistently defined products between the 

auction and day-ahead markets, LSEs cannot easily determine the set of CRR forward contracts being 

offered in the CRR auction. Load serving entities would likely find it difficult to purchase or set reserve 

prices on the CRR forward contracts if they do not know what forward contracts are actually available. 

22 Pacific Gas and Electric Company Conformed Long Term Procurement Plan, Attachment A, Clean Public Version, 2012, p.158: 

https://pgeregulation.blob.core.windows.net/pge-com~regulation-docs/BundledProcurementPian-Public.pdf. 

23 Southern California Edison 2015 General Rate Case Generation Volume 4- Power Procurement p.2: 

http://www3.sce.com/sscc/lawldis/dbattach5e.nsf /0/6A7265B21497F49F88257C21008007 A9/$FJ LE/SCE-02+Vol. +04.pdf 

San Diego Gas and Electric Company's 2006 Long Term Procurement Plan, p.l7: 

https:/lwww.sdge.com/sites/default/files/regulatory/2006LTPP·Redacted.pdf. 

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Department of Market Monitoring- California ISO November 2017 

Financial entities cannot be relied upon to bid auctioned CRRs up to their 

expected value 

Ratepayers face significant economic, regulatory and technical hurdles restricting them from effectively 

bidding in the CRR auction. Therefore, ratepayers cannot effectively raise the reservation prices of CRR 

forward contracts auctioned by the ISO from zero up to ratepayers' willingness to sell. 

However, CRR buyers competing for profitable CRRs might bid up the CRR prices. Because ratepayers 

are paid the auction revenue, they would receive the value of higher priced CRRs. If these CRR buyers 

compete by non-price methods, or transaction costs lower the buyers' willingness to pay, the auction 

prices they pay to ratepayers for the CRR forward contracts may not rise to expected CRR values. 

Non-price competition for CRRs is any action to obtain profitable CRRs other than raising the prices paid 

for CRRs. For example, by creating better transmission modeling and forecasting tools CRR buyers can 

find CRRs that are undervalued or modeled differently in the CRR auction than in the day-ahead market. 

Further, CRR auction participation is a complex undertaking: 

" ... a typical FTR [a.k.a. CRR] desk has to deal not only with standard roles of trading financial 

products, but also the technical ones of power analytics. Building and operating a successful FTR 

business is a complex enterprise, with multiple factors to consider. Additionally, the still exotic 

nature of the product makes standard solutions from the trading industry difficult to use." 24 

To trade in the complex CRR auction many CRR buyers employ PhDs in electrical engineering. The 

complexity of CRR trading indicates that transaction costs are high. Transaction costs are the costs, 

other than actual CRR prices, of transacting in the CRR auction. Transaction costs are not only faced by 

the actual buyers in the auction but also potential buyers who did not enter the auction. Potential 

transaction costs for CRR auction participation may include: 

Obtaining technical knowledge of power flow analysis, finance, and CRR markets 

Obtaining knowledge specific to the ISO transmission system, outages, and operations 

Collateral requirements limiting total trades" 

Company risk management policies, particularly for companies whose main business is not CRRs 

Time and effort spent searching for modeling differences 

Opportunity cost of participating in other markets 

CRR auction prices will likely fall as non-price competition and transaction costs increase. CRR buyers 

can also take advantage of having better and more flexible models of the day-ahead market models 

than the single model used in the CRR auction. With better models and better information, buyers can 

bid for CRRs they believe to be high value but which are modeled in the auction as low value. This is 

described in Section 4 above. 

Any one of these or other factors may be preventing buyers from bidding CRR auction prices up to their 

expected value. The non-ratepayer CRR profits from CRRs are clearly large and consistent. Returns of 

over 100 percent are not consistent with a competitive auction. 

24 Arce, Jose. "Trading FTRs: Real life Challenges~' in Financial Transmission Rights: Analysis, Experience and Prospects. Springer 

2013. Edited by Juan Rosell6n and Tarjei Kristiansen, p.271. 

25 Market participants must hold collateral for each megawatt of CRRs held as shown in Business Practice Manual for 

Congestion Revenue Rights Appendix H. Credit Requirement at: 

https://bpmcm.caiso.com/Pages/BPMDetails.aspx?BPM=Congestion%20Revenue%20Rights 

CAISO/DMM 25 
55 


Department of Market Monitoring- California !SO November 2017 

4 Alternatives to the CRR auction 

The !SO's day-ahead market is a centrally cleared market. In a centrally cleared market, power is not 

traded directly between market participants. It is sold to the market at the market price. Similarly 

power is bought/ram the market at the market price. The market price at any location is the locational 

marginal price. It follows that power is not shipped from one location to another. A CRR is not needed 

in order to have the ability or right to ship power between locations or for transmission access. 

The demand for a hedge against locational price difference primarily comes from forward contracting on 

power prices. Suppliers, load serving entities marketers and financial entities trade these forward 

power contracts outside the ISO markets. A supplier may sell a forward power contact at a location 

different than the locations of any generation assets it controls. When this happens, the day-ahead 

settlement prices for the forward power contract and the generator's energy schedule will be different. 

The supplier will face an uncertain day-ahead price difference not hedged by the forward power 

contract. A supplier may be willing to buy a forward contract for the day-ahead price difference to 

hedge this uncertainty. 

One alternative to auctioned CRRs would simply be a bilateral or exchange market for forward contracts 

for price differences between pairs of nodes. Forward contracts for price differences already exist in 

many markets today. They are called locational basis price swaps. A swap contract is relatively straight 

forward. The buyer of the swap pays the seller a price in the forward market. In return, the seller of the 

swap pays the buyer the spot price difference between two locations. Oren, Spiller, Varaiya and Wu 

detailed how pairs of forward contracts --one contract at the "source" location and one at the "sink" 

location-- could be bought and sold to create a hedge on locational price differences with the same 

effect as a locational basis price swap. 

Price swaps could be traded between willing counterparties either through an exchange or bi-laterally. 

Generators with forward power contracts at locations different than their generation assets would 

naturally benefit from decreased price differences between their power contract location and their 

generator location. The generators would be natural buyers of a locational basis price swaps. 

Load serving entities with forward power contracts --and who own the day-ahead congestion rents--

would benefit from increased price differences between the power contract location and the generator 

location. Thus, a load serving entities could be a natural seller of a locational basis price swap. The 

same parties that benefit from trading forward power contracts could also benefit from trading forward 

contracts for price differences. Unlike a CRR forward contract, a price swap would be consistently 

defined in the forward market and day-ahead market. The buyer of the price swap purchases the right 

to be paid the day-ahead price difference between two locations by the seller. In the day-ahead market, 

the price swap seller pays the buyer this price difference. This is in contrast to a CRR which can be an 

inconsistently defined product because it can be a different bundle of forward contracts in the CRR 

auction than in the day-ahead market. 

In a separate paper, DMM outlines several potential contract structures that can allow energy suppliers 

to hedge basis risk between the supplier location and trade hub reference prices using simple price 

swaps. Trade hubs give market participants a common reference price to settle forward contracts 

against and can increase the total potential trading partners available to energy suppliers and load 

27 
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Department of Market Monitoring- California ISO November 2017 

serving entities. Simple price swaps can be used to allow suppliers to hedge basis risk while contracting 

at trade hubs.2s 

There is no clear rationale for the ISO to offer forward price swaps. However, policy makers may 

determine that there are benefits to having the ISO provide a market for price swaps. Financial swap 

exchange markets external to the ISO or facilitated by the ISO would result in markets connecting willing 

buyers and sellers. Alternative markets should produce prices reflecting participants' willingness to 

trade. This is in contrast to the current CRR auction- which allows entities to buy forward contracts 

from ratepayers even though these ratepayers (or their load serving entities) have not offered to sell 

such contracts into the auction. A market based only on trades between willing participants would also 

greatly reduce the potential for large wealth transfers from ratepayers to other participants. With these 

alternative markets any generator, marketer, financial entity, or load-serving entity could buy or sell 

forward contacts to hedge or speculate on locational price differences. 

26 Department of Market Monitoring ~~Market alternatives to the congestion revenue right auction" November 27, 2017: 

http:ljwww.caiso.com/Documents/Market Alternatives CongestionRevenueRightsAuction~Nov27 2017.pdf 

28 
57 

Mr. UPTON. Thank you. 

Next, we are joined by Max Minzner, partner of Jenner & Block 

LLP. Welcome. 

STATEMENT OF MAX J. MINZNER 

Mr. MINZNER. Thank you. Thank you, Chairman Upton, Ranking 

Member Rush, committee members. I appreciate the opportunity to 

be here today. My name is Max Minzner. I am a partner at the law 

firm of Jenner & Block. From 2015 until 2017 I was the general 

counsel at the Federal Energy Regulatory Commission and from 

2009 to 2010 I was Special Counsel and the Director of Office Enforcement at FERC where I helped design and oversee the agency’s 

enforcement program. 

I believe that financial transactions play an important role in today’s energy markets. However, I think it is worth distinguishing 

between two types of financial transactions. First, some transactions occur within the RTO and ISO markets. Generally, those 

financial products take their value from the sales of physical energy and are designed to facilitate the sale of physical energy in 

some way. Those transactions are generally FERC-regulated. 

Second, some transactions in energy derivatives occur outside 

those markets. For example, trading can occur on ICE or NYMEX. 

To the extent that those transactions are regulated, the Commodity 

Futures Trading Commission oversees the markets where they are 

traded. This division leads to a core question for Congress and for 

Federal regulators: which products should be traded in the markets 

regulated by FERC and which products should be traded elsewhere? 

To answer this question the Commission should focus on its role 

as the regulator of transactions in physical energy. In my view, 

considering the expertise, mandate, and jurisdiction of the Commission, financial products should exist within the FERC markets to 

the extent that they are helpful to improve the functioning of these 

physical energy markets. They should not be created or expanded 

past the point at which they are needed to ensure that the physical 

markets work efficiently and deliver value to consumers. 

Right now, the financial products in the FERC markets generally 

serve this purpose. For example, virtual bids and offers can reduce 

price risk and improve reliability by aligning the prices in the dayahead and real-time markets for electricity. Similarly, FTRs allow 

entities to reduce their exposure to the risk of price variations. 

While these products do have real value for consumers, appropriate regulation of their trading by the Commission is important. 

For example, FERC has correctly worked to ensure that adequate 

credit requirements exist in the RTO and ISO markets. These requirements mandate that market participants have the financial 

ability to cover the obligations they assume. FERC also needs to 

carefully coordinate with other regulators. Given its jurisdiction, 

the CFTC has a role to play in this area. These two agencies need 

to work together to ensure coordinated regulatory efforts. 

A robust FERC enforcement program is also crucial. Financial 

products have played a role in many of FERC’s recent enforcement 

actions aimed at market manipulation. In particular, the Commission has often targeted a form of misconduct known as cross-marVerDate Mar 15 2010 13:10 Feb 15, 2018 Jkt 037690 PO 00000 Frm 00061 Fmt 6633 Sfmt 6633 I:\115THCONGRESS\115X81FINANCIALTRADERS\115X81FINANCIALTRADERSWORKING
58 

ket manipulation. Cross-market manipulation occurs when a market participant takes positions in two different but related markets. 

For example, a trader might obtain a large financial position in a 

product that derives its value from a relatively thinly traded physical energy product. 

By making large trades in the physical product, the trader might 

be able to change its price in ways that enhance the value of the 

financial position. Even if there is a loss on the physical position 

it can be offset by a much greater gain in the financial position. 

The Commission needs to make sure it has the analytic and oversight tools necessary to exercise its enforcement authority effectively and thoughtfully. 

Finally, the Commission should be open to improving its efforts 

in this area. These markets change quickly. As a result, the Commission should be frequently assessing the financial products and 

its markets, its regulatory approach, and its enforcement regime. 

Thank you again for the opportunity to be here today. I look forward to your questions. 

[The prepared statement of Mr. Minzner follows:] 

59 


One Page Summary of Testimony of Max J. Minzner 

Partner, Jenner & Block LLP 

November 29, 2017 

Financial transactions play an important role in today' s energy markets. FERC should 

make thoughtful choices when setting the scope of the products traded in its markets in order to 

allow them to provide the most benefit to consumers. Financial products should exist in the 

FERC markets to the extent that they help improve the functioning of the physical energy 

markets. 

Right now, the financial products in the FERC markets generally serve this purpose. For 

example, virtual bids and offers can reduce price risk and improve reliability by aligning the 

prices in the day-ahead and real-time market for energy. Similarly, FTRs allow entities to reduce 

their exposure to the risk of price variations. 

However, appropriate regulation of these products by the Commission is important. For 

example, FERC has correctly worked to ensure appropriate credit requirements that mandate that 

market participants have the financial ability to cover their obligations they assume. FERC 

should also carefully coordinate with other regulators. Given its jurisdiction, the CFTC has an 

important role to play in this area and the two agencies need to work together. 

A robust enforcement program is also crucial. Financial products have played a role in 

many of FERC's recent enforcement actions aimed at market manipulation. The Commission 

needs to make sure it has the analytic and oversight tools it needs to bring appropriate 

enforcement actions. 

Finally, the Commission should be open to improving its efforts in this area. These 

markets change quickly. As a result, the Commission should be frequently assessing the 

financial products in its markets, its regulatory approach, and its enforcement regime. 
60 


Testimony of Max J. Minzner 

Partner, Jenner & Block LLP 

Before the Committee on Energy and Commerce 

Subcommittee on Energy and Power 

United States House of Representatives 

November 29,2017 

Introduction 

Mr. Chairman, Ranking Member Rush, and members of the Subcommittee: Thank you 

for inviting me to testify today. My name is Max Minzner, and I am a partner at the law firm of 

Jenner & Block LLP. From 2015 until 2017, I was the General Counsel of the Federal Energy 

Regulatory Commission (FERC or the Commission). From 2009 until 2010, I served as Special 

Counsel to the Director of the Office of Enforcement at FERC where I helped design and oversee 

the agency's enforcement program. In my view, the Commission has worked hard to harness the 

power of markets, subject to regulatory oversight, to ensure the reliable and safe provision of 

energy to consumers at just and reasonable rates. 

I appreciate the opportunity to testify today on financial trading in the electricity markets. 

Financial transactions are a valuable component oftoday's markets and appropriate regulatory 

scrutiny is important to ensure a level playing field and the integrity of the markets. Let me start 

my testimony be distinguishing between two types of financial transactions. First, some 

transactions occur within the PERC-regulated markets. The Commission oversees six regional 

organized markets that handle wholesale transactions in electricity. These markets also trade 

financial products that take their value from the sales of physical energy. Second, some 

transactions in energy derivatives occur outside these markets. To the extent that these 

transactions are regulated, the Commodity Futures Trading Commission oversees the markets 

where they are traded. 

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61 


This division between leads to a core question for Congress and federal regulators: 

Which products should be traded within the markets regulated by FERC and which products 

should be traded elsewhere? 

In answering this question, I think the Commission and Congress should consider three 

factors. The first issue is the scope ofFERC'sjurisdiction. The Commission, at is core, is an 

agency that regulates transactions in physical energy products. The Federal Power Act and the 

Natural Gas Act regulate the sale of electricity and natural gas. The Commission is charged with 

ensuring that the rates, terms, and conditions of service comply with the requirements of those 

statutes. In contrast, as a general matter, FERC is not considered a financial regulator. 

Second, the Commission's jurisdiction shapes the scope of its expertise. The Commission 

and its staff have a deep understanding of the markets in electricity and natural gas. That 

understanding is built on eight decades of regulatory oversight under the Federal Power Act and 

the Natural Gas Act dating back to the work of the Federal Power Commission. Its regulatory 

experience with financial transactions will necessarily be more limited. 

Third, as the Commission authorizes products that are arguably also regulated by other 

agencies including the CFTC, the potential for regulatory conflict inevitably grows. Joint 

regulation by multiple agencies can have value, but comes with costs. Shared enforcement 

authority can provide a second set of eyes to identify and eliminate misconduct. On the other 

hand, entities that trade in these markets will need to comply with two sets of regulatory 

mandates. The burden of doing so can be significant. 

These factors suggests an answer to the question outlined above. Financial products 

should exist within the FERC markets to the extent that they are helpful to improve the 

functioning of the physical energy markets. They should not be created or expanded past the 

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62 


point at which they are needed to ensure that the physical markets work efficiently and deliver 

value to consumers. 

Right now, I believe the Commission's markets contain financial products that, broadly 

speaking, play this role. Let me highlight two of those products. The first are virtual bids and 

offers. Most FERC-jurisdictional markets operate on both a day-ahead and real-time basis. In 

the day-ahead market, buyers and sellers of power offer their supply and demand of electricity 

for the following day. These transactions are settled the next day and, to the extent that the 

supply or demand was not predicted correctly, the real-time market is available to close the gap. 

Differences between the day-ahead and real-time prices and quantities can distort market 

outcomes and lead to inefficiencies. Virtual bids and offers are valuable tools to close these 

gaps. Financial traders can observe anomalies in the day-ahead market that are likely not to be 

reflected in the real-time market. Through appropriate bidding strategies attempting to benefit 

from these anomalies, virtual transactions can cause prices to move and arbitrage away these 

differences. In certain situations, virtuals can also help reduce or eliminate market power. 

Second, many FERC markets offer a product called financial transmission rights or 

FTRs. These products take their value from the difference in day-ahead energy prices at two 

different locations on the electric grid. They can provide significant value to consumers of 

electricity because they allow entities to reduce their exposure to the risk of price variations. For 

example, load-serving entities have the obligation to provide power to retail customers. FTRs 

can allow these entities to hedge their risk of transmitting the power they need from generators to 

their customers. 

Allowing financial transactions in FTRs helps provide liquidity and price discovery. A 

liquid FTR market ensures that the costs ofFTRs are neither too high nor too low. Moreover, a 

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63 


liquid market can help improve decisions about transmission upgrades. Persistently high FTR 

prices reveal the existence of current or future congestion on the electric grid. These prices 

signal the need for new construction and assist transmission planners in their work. 

These benefits can be best achieved through a sensible and reasonable regulatory 

framework. Financial transactions need to be appropriately, but not overly, regulated. The 

Commission should avoid treating financial players differently just because they arc financial, 

rather than physical, participants in the jurisdiction markets. FERC should design the rules to 

maximize the benefit to consumers from these transactions. 

For example, regional variations in organization markets are significant. Each FERCjurisdictional market has its own unique market rules. These differences suggest that the nature 

and design of the financial products in each market may need to vary as well. 

The Commission should also ensure that the market rules relating to financial products 

are designed to avoid imposing costs on other market participants. One example of this type of 

regulation is appropriate credit requirements that ensure that traders have the financial ability to 

cover the obligations they assume. The Commission has taken important steps to impose such 

credit requirements and this helps ensure the financial solvency of the markets. 

FERC should also carefully consider the interaction between its rules and the 

requirements imposed by other regulators. Some have argued that aspects of the RTO markets 

are subject to CFTC regulation because of the nature of the financial products traded in these 

markets. The CFTC has provided an exemption for these markets given the pervasive regulation 

of the markets by FERC. Last year, the CFTC considered whether that exemption should extend 

to the private right of action under the Commodity Exchange Act. Working collaboratively with 

FERC, the CFTC eventually decided that the exemption should cover that provision as well. 

5 
64 


That type of thoughtful joint action by federal agencies will be important in this space moving 

forward. 

Finally, an appropriate and thoughtful enforcement regime is a crucial component of an 

effective program of regulatory oversight. Financial products have played a role in many of 

FERC's recent enforcement actions aimed at market manipulation. In particular, the 

Commission has often targeted a form of misconduct known as cross-market manipulation. 

Cross-market manipulation occurs when a market participant takes positions in two different, but 

related, markets. For example, a trader might obtain a large financial position in a product that 

derives its value from a relatively thinly-traded physical energy product. By making large trades 

in the physical product, the trader might be able to change its price in ways that enhance the 

value of the financial position. Even if there is a loss on the physical position, it can be offset by 

a much greater gain in the financial position. 

The Commission's focus on cross-market manipulation is a sensible use of its 

enforcement authority and has a strong historical pedigree. Congress gave FERC its expanded 

enforcement authority in the Energy Policy Act of2005. That statutory change was the direct 

result of the Western Power Crisis of2000-2001. An important component of that event was a 

combination of poor market design and the use of financial products to benefit from the 

manipulation of the physical energy markets. 

Despite its importance, though, cross-market manipulation is not always easy to detect 

and punish. In some cases, the conduct entirely within a FERC-regulated market because, for 

example, it involves physical and financial positions traded entirely within an RTO. In such 

cases, the Commission can "see" the entire transaction making detection more straightforward. 

On the other hand, though, components of the transaction only occur within the markets that the 

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65 


CFTC regulates. In such cases, the Commission may only be able to directly observe a part of 

transaction and will be required to coordinate with the CFTC to obtain other information that it 

needs. FERC and the CFTC have worked hard to build a collaborative and effective 

relationship. The Commission to continue those efforts. 

To its credit, FERC is an agency that has, from time to time, reexamined its enforcement 

practices. Let me highlight two of those efforts by FERC staff from November of2016. First, 

FERC staff issued a white paper on compliance practices for energy traders. Compliance is a key 

area for financial traders to consider because an effective compliance program can significantly 

reduce or eliminate the potential penalty exposure for enforcement targets. Second, staff issued a 

white paper reviewing the agency's anti-market manipulation efforts over the decade since 

EPAct 2005. Combined with the agency's annual report on enforcement, these documents 

provide key guidance to the regulated community about the Commission's enforcement priorities 

and its view on the scope of its enforcement authority. 

These efforts should continue. They are especially important in the area of financial 

trading. Financial markets inevitably move much faster than regulators. As a result, the 

Commission should constantly be reevaluating the financial products offered in its markets, the 

regulatory structure used to oversee these products, and the enforcement regime designed to 

ensure a level playing field for market participants and just and reasonable rates paid by 

consumers. 

7 
66 

Mr. UPTON. Thank you. 

Next, is it ‘‘Noah’’? 

Ms. SIDHORN. ‘‘No-ha.’’ 

Mr. UPTON. Noha—I am sorry—Sidhom, CEO of TPC Energy on 

behalf of the Power Trading Institute. Welcome. 

STATEMENT OF NOHA SIDHOM 

Ms. SIDHOM. Thank you. Good morning, Chairman Upton, Ranking Member Rush, and members of the subcommittee. My name is 

Noha Sidhom and I am CEO of TPC Energy, a privately funded 

power trading firm. I am here representing the views of the Power 

Trading Institute, otherwise known as PTI. PTI represents a diverse group of energy market participants ranging from large loadserving entities, suppliers, marketers, privately held commodity 

trading firms, as well as funds with investments in the power 

space. 

My comments here today will focus on financial transmission 

rights known as FTRs. FTRs are essentially the price of congestion 

from point A to point B on the grid. These congestion contracts reflect the increasing value of transmission as more and more power 

flows across the lines from power supply resources to the customers 

consuming electricity. A good analogy is a toll road where the tolls 

increase during rush hour. As road capacity becomes tighter with 

more commuters driving to and from work, the price to use that 

road increases. 

The same is true for electricity flow across the power grid. FTRs 

are purchased in an open and transparent auction that is connected by each RTO/ISO market. Market participants compete by 

submitting bids for specific megawatt quantity of FTRS on the 

transmission paths made available in the auction. 

From the inception of the organized markets, the Federal Energy 

Regulatory Commission directed the creation of FTRs as a means 

to provide open access to the transmission grid. Congress demonstrated its commitment to forward pricing in the Energy Policy 

Act of 2005 by directing FERC to undertake a rulemaking to implement long-term FTR auctions. And we think Congress was correct 

and forward-thinking in supporting that framework. 

Today, market participants utilize FTRs in a variety of different 

ways to the benefit of consumers. Load-serving entities who supply 

electricity to consumers utilize FTRs to hedge the risk of the price 

of congestion when serving their customers. Generation owners and 

developers utilize FTRs to hedge their risks to price volatility in 

the power markets. 

Financial participants provide liquidity and competition in the 

FTR market which contributes to maximizing the value of the 

transmission system, a benefit to load-serving entities. Financial 

participants also utilize FTRs by including them in portfolios of diverse products to provide competitive risk management and hedging services to load-serving entities, generation owners, and generation developers. 

FTRs save consumers money in three key ways. First, they provide an accurate price for the contracts that are allocated to transmission customers representing consumers. We are basically the 

tool on how to return those dollars back to transmission customers. 

67 

They provide a price for congestion on the grid to determine whether or not the cost of congestion is a more appropriate investment 

than the build-out of additional infrastructure. 

So essentially, do we just want to pay for the cost of congestion 

or do we need to build new infrastructure? That is really important 

because if we overbuild the system consumers are going to pay for 

that for decades to come and it is going to cost them billions of dollars. 

They provide a price signal to lenders financing infrastructure 

development and thus reduce the cost of financing. Over the past 

2 decades of implementing FTRs as a core component of RTO/ISO 

markets, certain practices have proven to be successful and should 

be adopted in every market. Long-term auctions need to be implemented. None of the ISOs are in compliance with Order 681 which 

mandated auctions that cover at least the 10-year period. Currently, the longest term is 3 years. 

Allocation of congestions costs caused by unplanned outages 

should be allocated to those who caused the costs to be incurred. 

New York ISO employs this practice and as a result has far fewer 

unplanned outages. Every other ISO should be encouraged to follow 

a similar practice. The FTR markets are robust and there is increased liquidity year-over-year. The Commission recently noted 

that there is zero evidence that a redesign of the FTR markets is 

warranted. 

That being said, there are challenges both in the FTR markets 

and in the markets in general that impact the way the FTR markets function. The key challenges at a high level are lack of transparency and outage scheduling; network model updates that are 

not consistent or transparent; the price formation efforts at FERC 

should be expanded and expedited; and the technology utilized by 

the RTOS and ISOs need significant improvement. 

Innovation and competitive prices for consumers are the core of 

our American economy. The Commission has spent the last 2 decades promoting these markets and the financial products that lie 

at the core of their creation and these economic concepts have 

worked to benefit your constituents. The way they think about electricity has fundamentally changed particularly over the last decade. Now we have to go the extra mile by ensuring market design 

flaws are fixed in short order, maintaining competition by expediting price formation efforts in long-term auctions, and pushing 

the RTOs and ISOs to take on a much-needed upgrade of their 

hardware and software systems. 

It is our responsibility as industry members to work with you, 

FERC, and other stakeholders to ensure that these markets remain 

competitive, liquid, and fair to continue to benefit consumers. We 

look forward to working on future improvements and thank you for 

the opportunity to testify here today. 

[The prepared statement of Ms. Sidhom follows:] 

68 


Noha Sidhom, CEO of TPC Energy, LLC on behalf of the Power Trading Institute 

Subcommittee on Energy 

Committee on Energy and Commerce 

U.S. House of Representatives 

Hearing: Examining the Role of Financial Trading in the Electricity Markets 

November 29, 2017 

I. INTRODUCTION 

Good morning Chairman Upton, Ranking Member Rush, and members of the 

Subcommittee. My name is Noha Sidhom, and I am CEO ofTPC Energy, a privately 

funded power trading firm with a focus on Financial Transmission Rights ("FTRs"). I am 

here representing the views of the Power Trading Institute ("PTI"). PTI represents a very 

diverse group of energy market participants, ranging from large load serving entities, 

suppliers, marketers, privately held commodity trading firms as well as hedge funds with 

investments in the power space. Our membership represents billions of dollars of 

investment in these markets, and a common thread for all of our companies is that we 

rely upon the financial products that are the subject oftoday's hearing in managing our 

day-to-day operations. PTI's mission is to advocate for markets that are open, 

transparent, competitive, and fair all of which are necessary attributes for markets to 

ultimately benefit electricity consumers. 

II. FINANCIAL PRODUCT OVERVIEW 

Similar to other commodity markets, there are many types of financial products that 

are utilized by market participants within wholesale electricity markets. These products 

range from the familiar standard futures contracts and their derivatives to more tailored 

products that are specific to the power industry. There are financial products that were 

created specifically as part of the development and implementation of the organized 

wholesale electricity markets operated by the various Regional Transmission Operators 

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69 


("RTOs") and the Independent System Operators ("ISOs"). All of these products are 

utilized by market participants to achieve diverse commercial objectives, which include, 

but are not limited to, securing revenue for an existing or future electricity supply 

resource, locking in electricity supply costs for consumers, or developing a portfolio of 

products in order to provide risk management and hedging services to other market 

participants. The trading of financial products results in a more competitive, liquid, and 

transparent overall wholesale electricity market, which benefits consumers at the retail 

level. 1 

The specific financial products that are part of the RTOIISO markets are Financial 

Transmission Rights ("FTRs"), which are products with tenors ranging from 1 month to 3 

years depending upon the RTO/ISO, and virtual transactions, which are products that are 

transacted in the next-day electricity market. This overview will focus on FTRs, 2 which 

are entitlements to receive or obligations to pay congestion revenues or charges on 

specified transmission paths on the power grid. 

To provide some background in order to understand FTRs, the value of transmission 

congestion is determined in the day-ahead and real-time electricity markets through a 

complex optimization process of balancing electricity supply and demand while honoring 

the physical and reliability constraints of the power grid. Simply put, congestion reflects 

the increasing value of transmission as more and more power flows across the lines from 

power supply resources to the customers consuming electricity. A good analogy is a toll 

road where the tolls increase during rush hour; as road capacity becomes tighter with 

1 See, e.g., Thomas, eta!., Electricity Customer Choice in Ohio: How Competition Has 

Outperformed Traditional Monopoly Regulation, Cleveland State University (20 16), 

available at 

http://engagedscholarship.csuohio.edu/cgi/viewcontent.cgi?article=2420&context=urban 

facpub; Compete Coalition, RTO and ISO Markets are Essential to Meeting our 

Nation's Economic, Energy and Environmental Challenges (2014). 2 Long-term financial contracts are referred to by various names, Financial Transmission 

Rights, Congestion Revenue Right and Transmission Congestion Contracts, in the 

different organized markets but they operate in essentially the same manner. 

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70 


more commuters driving to and from work, the price to use that road increases. The same 

is true for electricity flow across the power grid. 

FTRs are directional; that is, a holder may purchase a right from point A to point B on 

the grid. If power flow originates at point A (think of this as a generator) and terminates 

at point B (think of this as a city), and there is congestion between point A and point B, 

the holder of the FTR is entitled to receive that congestion value. 3 However, if the holder 

owns an FTR in the opposite direction (from point B to point A), the holder is obligated 

to pay the congestion value that exists from point A to point B. 

FTRs are purchased in an open and transparent auction that is conducted by each 

RTO/ISO. Market participants compete by submitting bids for a specific megawatt 

quantity ofFTRs on the transmission paths made available in the auction. The auctions 

are conducted on a forward basis. For example, an auction for FTRs that span an entire 

year is run prior to the start of the year. There is a finite number of contracts that are 

auctioned off based upon the expected capability of the system. Each RTO!ISO uses an 

algorithmic model to determine who is awarded FTRs and at what price. The proceeds of 

the auction are distributed primarily to load serving entities, who supply electricity to 

consumers. 

The competitive process of the auction provides the incentive for a market participant 

to bid economically in order to be granted FTRs. The results of each auction are made 

public to all stakeholders and what is unique to FTRs is that the owners of these contracts 

are also made public. Therefore, anyone can visit a particular RTO's/ISO's website to see 

which entities were awarded contracts and the prices associated with those contracts. 

These prices represent the forward price of congestion. 

3 RTOs!ISOs calculate prices at specific locations on the grid. The difference in prices 

between two locations on the grid, after adjusting for the value of electricity that is lost 

across transmission lines, is the value of congestion between those two locations. 

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71 


From the inception of the organized markets, the Federal Energy Regulatory 

Commission ("FERC" or "Commission") directed the creation of FTRs as a means to 

provide open access to the transmission grid. The FTR product was approved nearly two 

decades ago by the Commission. 4 FERC found that FTRs "provide an effective method 

of protecting against incurrence of congestion costs when suppliers engage in 

transactions that use their firm transmission service reservations." 5 

Congress' recognition of the value of FTRs is most notable in Section 217 of the 

Energy Policy Act of2005 (the "native load" provision). Through Section 217, Congress 

directed FERC to: 

exercise the authority of the Commission under this Act in a 

manner that ... enables load-serving entities to secure firm 

transmission rights (or equivalent tradable or financial 

transmission rights) on a long-term basis for long-term power 

supply arrangements made, or planned, to meet such needs. 

Further, Congress demonstrated its commitment to forward pricing in the organized 

markets by directing FERC to undertake a rulemaking to implement long-term FTR 

auctions, Order No.681, 6 and we think Congress was correct and forward thinking to 

support long-term auctions. 

III. FINANCIAL TRANSMISSION RIGHTS ARE KEY FOR CONSUMERS 

FTRs are inextricably linked to the underlying delivery of power to customers, and 

they are integral to shielding consumers from the price volatility that comes with having 

to perfectly balance the grid every minute of the day. Today, a variety of market 

participants utilize FTRs in a variety of different ways to the benefit of consumers. 

4 Pennsylvania-New Jersey-Maryland Interconnection, 81 F.E.R.C. 161,257 (1997). 5 Id. 1162,257, 62,260. 6 Long-Term Firm Transmission Rights in Organized Electricity Markets, Order No. 681, 

FERC Stats. and Regs. 1 31,226 (2006). 

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72 


Load serving entities, who supply electricity to consumers, utilize FTRs to hedge 

the risk of the price of congestion when serving their customers. Generation owners and 

developers utilize FTRs to hedge their risk to price volatility in the power markets. 

Financial participants provide liquidity and competition in the FTR market, which 

contributes to maximizing the value of the transmission system, a benefit to load serving 

entities. Financial participants also utilize FTRs by including them in portfolios of 

diverse products to provide competitive risk management and hedging services to load 

serving entities, generation owners, and generation developers. Lending institutions who 

finance generation and transmission facilities often require use ofFTRs and other 

bilateral transactions in order to hedge the risk of their investment. Without a proper 

forward price curve that is developed by forward congestion values from FTR auctions, 

suppliers, load serving entities, financial participants, and financial institutions would 

have to build in substantial risk premiums in order to be able to take on such significant 

risk without any type of hedging opportunity. This would effectively be a dead weight tax 

on consumers. Therefore, without FTRs, electricity prices would undoubtedly increase 

for ratepayers. 

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Financial Participants Play an Important Role in the Markets 

Financial participants are positioned to offer a varlery of transaction structures and risk 

management services to other market partie/pants and provide ilquldlry and competition, all of 

which facilitate a robust market place. A robust market place Is key In ultimatetv driving value for 

consumers of electricitv. 

Another critical point to note is that the forward price signal that FTRs provide to the 

market leads to more efficient infrastructure development. The organized markets have to 

balance the need for additional infrastructure development with the cost of congestion. 

Does it make sense to build a new transmission line or a new plant in a particular region 

or pay for the cost of congestion in that region, if that would overbuild the system to the 

detriment of consumers? The only way to answer that question is to have a forward price 

curve where willing buyers and sellers take on economic risk and provide a forward price 

7 This figure demonstrates the various ways financial participants can be positioned in the 

market. 

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signal to evaluate the need for such infrastructure. It is important to note that the 

organized markets have not seen load growth over the past several years. 8 Overbuilding 

the system thus would be an unnecessary cost that consumers would bear for decades to 

come. The inextricable link between FTRs and the grid and the nature of their locational 

pricing make them a necessary tool for providing that balance. 

You may be asking yourself, where does the money come from? Are the funds being 

paid to these FTR holders coming out of my constituents' pockets? The answer is a 

resounding no. Let's take a step back. The organized markets allocate FTRs principally to 

utilities that serve retail customers. These rights in total reflect the expected physical 

capability of the transmission system to deliver electricity; they are finite and their 

number is determined through analyses conducted by the organized markets. These finite 

rights are allocated to the transmission customers representing consumers that have paid 

for the fixed investment in the transmission system and are thus entitled to rights to the 

electricity transfer capability of this system. Transmission customers are allocated a 

certain number of contracts. How do we determine the value of these contracts that are 

provided to the transmission customer? It is important to note that only a percentage of 

these contracts are actually auctioned off, the majority are allocated. In fact, only the 

excess capacity is auctioned off in the FTR auction. The value of the allocated rights is 

then determined in the open auction. Bilateral contracts are also priced off of the auction 

price. Basically, this is a public auction of excess capacity. 

When there is no liquidity in the open auction or competition to arrive at an efficient 

price, the value of that contract diminishes because parties build in a risk premium. 

8 See, e.g., PJM Interconnection, L.L.C., Where has Electricity Demand Growth Gone in 

PJM and What are the Implications? (2014), available at 

https :/ /www .eia.gov/ conference/20 14/pdf/presentations/sotkiewicz.pdf; see also Analysis 

Group, Electricity Markets, Reliability and the Evolving U.S. Power System 27-28 

(20 17), available at 

http:/ /www.analysisgroup.com/uploadedfiles/ content/insights/publishing/ ag_ markets _reli 

ability _finaljune_2017.pdf. 

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Simply put, without a locational FTR market construct, there is no mechanism to price 

bilateral contracts or allocated rights. 

In short, FTR auctions save consumers money in three key ways: 

They provide an accurate price for the contracts that are allocated to transmission 

customers representing consumers. 

They provide a price for the congestion on the grid to determine whether or not the 

cost of congestion is a more appropriate investment than the build out of 

additional infrastructure. 

They provide a price signal to lenders financing infrastructure development and 

thus reduce the cost of financing. 

Some have argued that FTRs should not remain part of the RTO!ISO paradigm and 

that they should be traded outside the electricity market construct on a separate exchange. 

As discussed above, however, these rights are inextricably linked to the transmission 

system. The pricing of these rights is utilized in the transmission planning process; the 

number of rights allocated shifts based on the physical capability of the grid in a manner 

only the RTOIISO can model and alter. And only the RTO and ISO can reconfigure the 

actual right, meaning they can change the path from A to B to A to C, if that is the more 

appropriate configuration that needs to be priced and allocated. In fact, FERC recently 

opined on the reconfiguration and reallocation of rights in PJM. Historical rights that 

were not reflective of the current transmission system were being allocated and that was 

causing distortions in the modeling and pricing. FERC mandated that PJM update its 

allocation process to allocate rights based on the current system and clearly stated that 

there is no evidence that the FTR market warrants a redesign. 9 Only the RTOs!ISOs can 

model the physical system constraints that will be applicable for the period auctioned in 

order to determine an appropriate price based upon the preferences of willing buyers and 

9 PJM Interconnection, L.L.C., Order on Rehearing and Compliance, 158 F.E.R.C. ~ 

61,093 (2017). 

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sellers. In addition, FTRs are paid from day-ahead revenue that is not just an exchange of 

money between FTR traders but rather a blend of complex activity by all market 

participants, including generation owners and load serving entities. An exchange would 

not incorporate this activity. As a result, taking these products to an exchange separates 

rational congestion management activity from the economic activity to balance supply 

and demand on the transmission grid and would ultimately increase costs for consumers. 

From a legal perspective, such a divided structure would go against the core principles of 

Order No. 888, 10 the key FERC order instituting open access. Incidentally, this structure 

is being discussed in the California stakeholder process and stakeholders have voiced 

these very same concerns. 

Lastly, a forward price curve increases innovation by providing a price signal for 

entrepreneurs to invest in new technologies. Without such a forward price signal, 

investors would find it difficult to develop R&D budgets to explore new technologies not 

knowing the potential future value of such an effort. The organized markets have 

demonstrated this consumer benefit because indeed they have been a breeding ground for 

innovation. 11 For example, the organized markets were key markets for developers of 

increasingly cost-effective renewable energy generation facilities; they were the test beds 

for pioneering storage technologies and customer distributed generation, efficiency and 

demand response resources. The structure of these markets was also a driving force 

behind companies supplying new and improved methods for measuring and tracking all 

aspects of the physical system providing increased transparency. Lastly, these markets, 

and these financial products specifically, have also promoted the emergence of a 

10 Promoting Wholesale Competition Through Open Access Non-discriminatory 

Transmission Services by Public Utilities and Recovery of Stranded Costs by Public 

Utilities and Transmitting Utilities, Order No. 888, 61 Fed. Reg. 21,540 (May 10, 1996), 

FERC Stats. & Regs.~ 31,036 (1996). 11 PJM Interconnection, L.L.C., Resource Investment in Competitive Markets (May 5, 

20 16), available at http://www. pjm.com/-/mediallibrary/reports-notices/specialreports/20 160505-resource-investment-in-competitive-markets-paper.ashx ("PJM 2016 

Resource Investment Whitepaper"). 

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sophisticated financial sub-industry designed around the analysis of price and the 

forecasting of all major characteristics of variability and risk. 

IV. BEST PRACTICES IN FTR MARKETS 

Over the past two decades of implementing FTRs as a core component of RTO/ISO 

markets certain practices have proven to be successful and should be adopted in every 

market. We will address those best practices here but one thing we would like to stress to 

the Subcommittee is that at a broader level there needs to be a mandate for the RTOs and 

ISOs to evaluate and implement best practices, not just pertaining to FTRs but pertaining 

to overall market functions. 

a. Long-Term Auctions Need To Be Implemented 

We applaud PJM, New York and ERCOT for implementing a long-term FTR auction 

construct. PJM, New York and ERCOT are the only markets that have an FTR auction 

with a duration longer than one year. PJM and ERCOT have auctions going out as far as 

three years and New York has a two-year auction. This forward-looking price signal 

enables better price formation, more cost-effective infrastructure development, more 

efficient pricing of hedges and, as a result, consumer savings. However, none of the ISOs 

are in compliance with Order No. 681, which mandated auctions that cover at least a 10-

year period. The logic behind the 1 0-year period mandate was to cover the planning 

horizon that is utilized in the transmission planning process. Specifically, Order No. 681 

stated that: 

Long-term firm transmission rights must be made available with term lengths 

(and/or rights to renewal) that are sufficient to meet the needs of load serving 

entities to hedge long-term power supply arrangements made or planned to 

satisfy a service obligation. The length of term of renewals may be different 

from the original term. Transmission organizations may propose rules 

specifying the length of terms and use of renewal rights to provide long-term 

coverage, but must be able to offer firm coverage for at least a 10-year 

period. 12 

12 Order No. 681, at 255. 

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While the RTOs and ISOs allocate rights to transmission customers for a 10-year 

period, they do not auction offFTRs for a 10-year period. The flaw with this paradigm is 

that there is no long-term forward price for that allocated right. This is akin to my giving 

you I 0 shares of a stock and telling you I will tell you what it is worth in seven years. All 

of the FERC jurisdictional RTOs/ISOs should be mandated to come into compliance with 

Order No. 681 and implement long-term auctions. One to three year terms are simply not 

sufficient to provide liquidity for longer-term hedging or price discovery. 

b. Allocation Of Congestion Costs Caused By Unplanned Outages Should be 

Evaluated 

The New York ISO allocates congestion costs incurred due to unplanned transmission 

outages back to the transmission owner. As a result of this practice, New York ISO has 

far fewer unplanned outages and the transmission owners are diligent in communicating 

system maintenance to system operators. For example, as ofNovember 26,2017, PJM 

had 2,208 active and planned outages in total for the month; 1,178 were forced outages. 

New York, on the other hand, had 908 total planned or active outages for the month and 

only 243 forced outages. 13 

Market participants build a premium into their price for FTR contracts to manage the 

risk of these unplanned outages. New York ISO's approach to make those in control of 

the outage schedule accountable for the cost incurred to the system creates the right 

incentives, and based on the data, that economic incentive works. This practice also helps 

maintain reliability of the grid by communicating outages to the RTO/ISO in a timely 

manner. Every other RTO/ISO should be encouraged to follow a similar practice. 

c. Options Contracts Should Be Made Available As A Risk Management Tool 

13 This outage information was obtained from Yes Energy, a third-party vendor, and only 

pertains to lines over 69 kV. 

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ERCOT is the only market that allows for the purchase of an FTR options contract at 

every path that is available for a traditional FTR contract. Options allow a market 

participant to limit their exposure by paying a premium for the option and locking in their 

downside to the transaction. Other markets have options for FTR contracts, but the 

availability of paths is very limited. Options are heavily utilized in ERCOT because they 

are an effective risk management tool. If all of the potential FTR paths were made 

available as an options contract, this tool would be utilized by market participants in 

every RTO/ISO to balance portfolios. A good way to think about this is comparing it to 

options in the equities market. Imagine if you were only able to purchase options of 

certain stocks but not others. In other words, the equities market would allow you to pay 

a premium for certain stocks but not others. This biases price discovery and limits a 

market participant's ability to manage risk by paying a premium to better manage 

downside risk. 

V. CHALLENGES FACING MARKET PARTICIPANTS IN THE FTR 

MARKETS 

The FTR markets are robust and there is increased liquidity year over year. To 

reiterate, the Commission recently noted that there is zero evidence that a redesign of the 

FTR markets is warranted. 14 That being said, there are challenges both in the FTR 

markets and in the markets in general that impact the way the FTR markets function. We 

address those challenges below. 

a. Lack of Transparency in Outage Scheduling 

14 See PJM Interconnection, L.L.C., Order on Rehearing and Compliance, 158 F.E.R.C.,; 

61,093 (20 17) ("[T]he Market Monitor and Joint State Commissions reiterate the 

proposal ... that the Commission should support a market redesign to ensure loads 

receive all congestion revenues. We reject the arguments that the sole purpose ofFTRs is 

to return congestion revenue to load and the market should therefore be redesigned to 

accomplish that directive."). 

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As demonstrated above, there is a lack of transparency regarding the scheduling of 

outages. This lack of transparency costs consumers money because market participants 

have to build in a risk premium into their transactions to account for this prevalent 

practice of unplanned transmission outages. The New York ISO's practice of allocating 

costs caused by an unplanned outage back to the transmission owner and thus decreasing 

the number of unplanned outages clearly demonstrates that this problem can and should 

be solved. 

b. Network Model Updates Are Not Consistent or Transparent 

Market participants have very little transparency into updates to the network 

model that significantly impact the pricing of FTR contracts. Each ISO has a different 

practice for releasing model updates and they are often not released in a timely manner. 

Furthermore, often the amount of capacity that is auctioned off is drastically different 

from the prior auction with no notice and no transparency into the changes being made to 

the model. A consistent schedule for all of the RTOs/ISOs to release network model 

updates prior to FTR auctions would: (1) assist with more accurate price formation of the 

forward curve; (2) reduce any risk premium incurred by consumers due to this 

uncertainty; and (3) reduce pricing issues at the seams caused by disclosure of 

information in one market but not the other. 

c. Revenue Adequacy Issues Have Been A Concern 

The majority of the capacity on the system is allocated to load serving entities and 

excess capacity is auctioned off in FTR auctions to value both the allocated rights and the 

auctioned rights. The process of allocating the right-sized amount of capacity is not an 

easy one to get one hundred percent right, one hundred percent of the time. When too 

much capacity is allocated or auctioned off, there can be a revenue shortfall. In other 

words, there may not be enough day-ahead revenue to pay all of the holders of the 

transmission rights. At the outset, this is an issue a minority of the time. PJM experienced 

revenue adequacy issues from 2011 to 2014, but over the past 12 years, only three years 

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have presented significant revenue concerns. 15 In PJM from 2005 to 2012, total net 

congestion costs were $11.3 billion, while auction revenues were $11.5 billion, resulting 

in excess funding. This demonstrates that the current market structure provides an 

efficient means to entitle holders of the allocated rights to the full economic value of the 

whole transmission system. The Commission closely evaluated this issue and was clear in 

stating that a redesign was not necessary. The FTR market is operating as intended and 

returns value back to consumers. 

That being said, a lesson can be learned from the revenue adequacy concerns 

voiced by state regulators and others. Unplanned transmission outages and modeling 

issues have been the primary causes of underfunding. 16 Revenue inadequacy is not 

caused by the FTR product but rather by market design flaws that need to be resolved. 

Without the FTR product you would lose the transparency that highlights these market 

design issues. And there is no other way to value the allocated rights without the FTR 

product. It is the only fair and transparent way to price congestion and provide open 

access. The open auction process is integral for consumers because it is transparent as to 

ownership and competitive as to price. However, these market design flaws do cost 

consumers money because they force investors to build in a risk premium. The more 

confident market participants are in the design of the market, the better value consumers 

will get for the allocated rights. This revenue adequacy issue presents an opportunity for 

both FERC and this Subcommittee to take a critical look at improvements that can be 

made to RTO/ISO processes to ensure that consumers are in fact protected from revenue 

shortfalls caused by market design flaws. 

d. Price Formation Efforts At PERC Should Be Expanded And Expedited 

15 The plarming periods of2011-2012, 2012-2013 and 2013-2014 were revenue 

inadequate by over 15 percent. 16 See PJM Interconnection, L.L.C., Proposed Modifications to ARR and FTR Provisions, 

Docket No. EL16-6-000, at 7 (Oct. 18, 2015). 

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FERC has initiated several rulemakings over the past two years to improve price 

formation in the organized markets. The rulemaking regarding uplift allocation, which is 

essentially an out of market payment made to a unit that is called on in real-time to meet 

system needs, has not been finalized. In addition, the price formation docket was started 

in 2014, and the discussion regarding price formation has evolved significantly since that 

time. Today, we are discussing pricing attributes, not just environmental attributes but 

ramping capability and other functions that have become more integral as technology 

improvements have been made. These elements need to be folded into the discussion at 

FERC. In 2012, FERC held a technical conference on capacity markets and all of the 

economists called on to testify at that conference stated that the Commission should focus 

on getting the prices right in the energy markets. At that time, approximately ninety 

percent of the revenue in the wholesale market was earned in the energy markets. Today, 

approximately seventy percent of the revenue is earned in the energy market. 17 FERC has 

not taken speedy action on price formation issues and that has exacerbated some of the 

concerns voiced by generators that they cannot recover their costs. Expediting efforts to 

improve price formation in the wholesale market to provide a more transparent cost of 

delivering power would greatly benefit consumers and market participants. 

e. The Technology Utilized By The RTOs/ISOs Needs Significant Improvement 

Another significant challenge faced by market participants is the inadequate 

technology utilized by the RTOs/ISOs. Many of the systems utilized by these organized 

markets have not had a significant upgrade in over a decade. PJM, MISO, and CAISO 

have all experienced significant issues in solving their FTR models over the past several 

years. Most notably, PJM was recently a week late in solving its auction and did not solve 

until the settlement month began. In other words, market participants were incurring 

17 Monitoring Analytics, LLC, State of the Market Report for PJM, Vol. 2: Introduction, 

at 16-17 (Mar. 9, 2017), available at 

http://www.monitoringanalytics.com/reports/P JM State o[ the Market/20 16120 16-sompjm-volume 1.pd( 

15 
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profits and losses but did not know which positions they had been granted in the auction 

until several days into the settlement month. This does not occur in any other commodity 

market. 

Some RTOs/ISOs have suggested eliminating products, reducing transaction volume 

of certain products or have not implemented products suggested by their market monitors 

due to technology constraints. What this really means is that we are hindering price 

formation and liquidity in the market in the name of inadequate technology. This practice 

cannot continue. Large financial institutions as well as our intelligence community all 

process significantly larger sets of data in a small fraction of the time demanded of the 

RTO/ISO markets. The technology is out there and given the critical nature of our energy 

infrastructure to the United States economy, we should be deploying the most advanced 

technology practicable. In addition, there should be some level of transparency as to 

hardware and software upgrades made by the RTOs/ISOs to ensure that upgrades are 

occurring as necessary and that funds are being deployed in a manner that benefits 

consumers. Several years ago, the Department of Energy ("DOE") provided a $3 million 

grant to MISO to improve its day-ahead solution time as part of an effort to improve gas 

and electric market coordination. The goal was to allow for improvements so that MISO 

can release commitment results earlier and allow market participants to have that 

information prior to the close of the gas nomination cycle. Stakeholders have not been 

informed of how those funds were utilized and what improvements have been made to 

the day ahead engine. PTI is aware that PJM was also involved in that effort, but to our 

knowledge, a set of best practices or potential improvements has not been shared. It is our 

belief that more transparency regarding technology upgrades as well as additional 

information sharing between the RTOs/ISOs would result in better operation of the 

markets and save consumers significant dollars. 

f Procedural Changes Could Improve An Already Robust Enforcement 

Program 

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PTI strongly believes that PERC must have a robust enforcement program that has the 

tools necessary to prosecute bad actors in the market. None of our members want to 

engage in and deploy significant capital in a market that is not rigorously policed. And 

indeed, these markets are adequately policed with multiple layers of protection. First, the 

Market Monitor in each RTOIISO has a wide latitude of discretion to request information 

regarding a market participant's transactions, provide guidance, make recommendations 

and refer cases to the Office of Enforcement. Second, PERC's Office of Enforcement has 

more than doubled in size over the past eight years and has been extremely active in 

policing the markets. Lastly, while the CFTC exempted financial transactions in the 

RTOIISO markets from most of its statutory requirements, the CFTC made clear that it 

was not exempting these transactions from its enforcement authority. 

Noting all those layers of protection, we think it is important to look at the number of 

investigations that do not result in any action by PERC. In 2017, while the Commission 

closed 16 investigations, 11 were closed without further action because staff concluded 

that the evidence did not support finding a violation. The 2016 Enforcement Report noted 

that the Commission closed 11 investigations with about half concluding no action was 

necessary. 18 

The 2017 Enforcement Report also noted two items of particular interest. First, the 

Commission conducted a full audit of a financial trading firm and concluded that no 

changes were necessary. Second, surveillance screens identified large, loss making 

virtual increment offers (INCs) at an RTO Hub placed by a market participant who held a 

leveraged FTR path sourcing at that same hub. The Division oflnvestigations contacted 

18 Staff of the Office of Enforcement, Fed. Energy Regulatory Comm'n, 2017 Report on 

Enforcement, Docket No. AD07-13-0ll, at 7 (2017); Staff of The Office of Enforcement, 

Fed. Energy Regulatory Comm'n, 2016 Report on Enforcement, Docket No. AD07-13-

010, at 7 (2016). 

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85 


the market participant and was informed that the entity held a tolling agreement with a 

generation facility in the RTO and that the contract priced against the real time locational 

marginal price. The market participant explained that the observed INCs covered a period 

of a planned outage, and that the virtual position shifted a non-leveraged real-time 

position to the day ahead market where the market participant hedged commodity risk. 

After verifying the information, the Commission closed the case. We note these examples 

to highlight that the nature of these transactions is complex, and thus they may lead to 

more of a dialogue with the Office of Enforcement, but this does not translate into illintended behavior in the market by financial participants. 

Enforcement efforts come at a cost to market participants and ratepayers. Over the 

past five years, the Commission has gone from a compliance approach to its enforcement 

program to a surveillance approach. This change in dynamic has chilled the open 

dialogue that once existed between enforcement staff and industry. We believe simple 

procedural changes could be made to FERC's enforcement program to make it more 

effective for both the Commission and market participants. The first procedural change is 

requiring FERC staff to request the data prior to requesting the speaking documents (i.e., 

emails, IMs, employment contracts, etc.). The statute is a fraud-based statute with an 

intent element. One must establish fraud first and then go to the intent element. The 

speaking documents go to the intent portion and thus are not necessary until an analysis 

of the data has been completed to determine whether in fact bad behavior occurred. The 

speaking documents are also incredibly expensive to produce. There are many occasions 

where market participants have incurred millions of dollars of expenses producing 

speaking documents, only for enforcement staff to find no manipulative behavior in their 

review of the transactional data. These are unnecessary dollars spent. 

The second procedural change is to allow for a non-public no-action letter process, 

similar to that available at other federal market regulators like the Securities and 

Exchange Commission and the Commodity Futures Trading Commission. Currently, 

FERC only has a public no-action letter process. The key issue here is that if a market 

18 
86 


participant wants to vet a strategy with the Commission, the market participant must then 

share its proprietary trading strategy with all of industry. FERC has stated that it would 

like to share its insight on these strategies to benefit all of industry and provide more 

transparency. However, an easy solution for this would be to only make public 

information regarding strategies where the Commission declines to issue a no-action 

letter. In other words, if the Commission thinks the transaction is in a gray area and 

would not issue the no-action letter, then it should make the details of that transaction 

(not the market participant) public to place others on notice that it views that particular 

strategy as potentially manipulative market behavior. If the Commission grants a noaction letter, it should keep the details of that market participant's proprietary strategy 

confidential. 

Third, the Commission runs financial screens across positions and when those screens 

are triggered, an investigation can be initiated. The Office of Enforcement should make 

those screens public. There should not be an effort to hide the ball. Getting access to such 

screens would help companies build out better compliance programs, facilitate discussion 

between enforcement staff and market participants regarding the transactional data, and 

shed light as to Enforcement's views on what is considered market manipulation. 

Fourth, the Commission should be encouraged by Congress to resolve enforcement 

actions as soon as practicable. Investigations sit idle for years making discovery more 

cumbersome and impacting businesses in a negative manner. 

VI. CONCLUSION 

Innovation and competitive prices for consumers are the core of our American 

economy. The Commission has spent the last two decades promoting these markets and 

the financial products that lie at the core of their creation. And these economic concepts 

have worked to the benefit of your constituents. The way they think about electricity has 

fundamentally changed, particularly over the last decade. Now we have to go the extra 

mile by: 

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• Ensuring market design flaws are fixed in short order. 

• Maintaining competition by expediting price formation efforts and long-term 

auctions. 

• Pushing the RTOs and ISOs to take on a much-needed upgrades of their 

hardware and software systems. 

• Ensuring ISO/RTOs are implementing best practices and not delaying to the 

detriment of consumers. 

• Maintaining a robust enforcement program at the Commission by making 

necessary procedural changes to re-open the dialogue between enforcement 

staff and industry to the benefit of consumers. 

It is our responsibility as industry members to work with you and FERC to ensure that 

these markets remain competitive, liquid, and fair to continue to benefit consumers. We 

look forward to working on future improvements and thank you for the opportunity to 

testify here today. 

20 
88 

Mr. UPTON. Thank you. 

Next, Vince Duane, senior VP and general counsel for PJM, welcome. 

STATEMENT OF VINCENT P. DUANE 

Mr. DUANE. Thank you, Chairman, Ranking Member, members 

of the subcommittee. My name is Vince Duane. I am a senior vice 

president of PJM, and like my colleague to the right, Dr. 

Hildebrandt, I work for an organization that administers these 

markets, we don’t participate in them. Indeed, our mission is simply to deliver wholesale electricity at the lowest possible cost to the 

consumer. And the litmus test for financial trading in these markets is whether it furthers that mission. Quite simply that is the 

question. 

There are two points I would like to bring out to the committee’s 

attention that bear on that question and that are unique to these 

electricity markets like PJMs. First, our core function is a physical 

function. We commit generation for sale and purchase and deliver 

it to the ultimate consumer. We do this with the assistance of financial products that trade alongside physical transactions and 

that is something that makes us quite unique relative to other 

commodity markets where primary physical markets are quite separate and distinct from secondary financial and derivative markets. 

We are a little bit of a hybrid in our financial markets because 

we believe that financial products can bring liquidity, they can 

bring price convergence, and can bring pricing discovery to assist 

in the operation of the physical market, but that is the standard. 

There is no other independent basis for these types of transactions 

to exist in these FERC-regulated markets unless they meet that 

standard. There are other places for them to go. 

We have in this industry our own secondary financial markets. 

Mr. Minzner made reference to some of them—NYMEX, Intercontinental Exchange. There are places to go outside of the FERC-regulated markets if there are other needs for financial traders and 

hedgers. The second point I would like to make is that these markets are complex. I don’t think I need to say that but I will start 

with that point. 

Some of you may have heard the term market design and indeed 

these FERC-regulated markets are very heavily engineered, very 

much rule-focused. We use rules, thousands of pages of rules, in 

fact, that are on file with the FERC in the form of a PJM tariff, 

and underlying those rules are models and algorithms that do two 

things generally. 

One, we use these things to dispatch and commit generation to 

meet load to keep the lights on in the system and we do that in 

a way that sets prices. So when you have prices that are formed 

at least in part by market design, by rules and algorithms, we have 

learned a few interesting things over time. 

First, price dislocations can and do occur, and if these dislocations are caused by a rule feature or by a modeling difference, no 

amount of financial trading is going to correct those price dislocations. In fact, it will just simply exploit and profit that dislocation 

without bringing the arbitrage value that you would theoretically 

expect to see. 

89 

Revenues in these systems are highly contested between asset 

owners and consumers. So where trading exploits a price dislocation without bringing any corrective value, essentially it is just siphoning revenues out of that system. It is a hole in the bucket and 

it is something that needs to be plugged as a hole in the bucket. 

So in conclusion, the question is whether financial trading in 

these FERC wholesale electricity markets bring value. My answer 

is yes, but with qualification. The important point is you cannot assume the efficiency values that you would normally see in purely 

financial markets such as those administered by the SEC or the 

CFTC. 

Those values are necessarily going to hold in these unique physical electricity markets. But if they are rationalized and if these 

trades are incented properly and if they are limited where necessary, they can bring benefits. They do bring benefits and transaction efficiency to the physical generation owner, to the transmission customer, and ultimately to the consumer. Thank you very 

much. 

[The prepared statement of Mr. Duane follows:] 

90 


United States House of Representatives 

Committee on Energy and Commerce 

Subcommittee on Energy 

Testimony of Vincent P. Duane, Senior Vice President, Law, 

Compliance & External Relations 

PJM Interconnection, L.L.C. 

"Examining the Role of Financial Trading in the Electricity Markets" 

November 29, 2017 

My name is Vincent Duane and I serve as a Senior Vice President at PJM 

Interconnection, L.L.C. ("PJM"). I have worked in competitive wholesale electricity 

markets regulated by the Federal Energy Regulatory Commission ("FERC") since their 

inception over 20 years ago, including over 5 years on the floor of a major energy 

trading firm active in PJM and the other FERC-regulated electricity markets. PJM is a 

Regional Transmission Organization ("RTO") responsible for ensuring the reliable and 

non-discriminatory planning and operation of the transmission grid and the fair and 

efficient administration of wholesale electric markets. The PJM region encompasses 

over 65 million people in an area that includes all or parts of New Jersey, Pennsylvania, 

Delaware, Maryland, the District of Columbia, Virginia, North Carolina, West Virginia, 

Kentucky, Ohio, Michigan, Indiana, Illinois and Tennessee. 

Thank you Chairman Upton and the Subcommittee on Energy for inviting PJM to 

address this subject. The 'bottom line' of my testimony today is that financial trading in 

the wholesale electricity markets can enhance liquidity, aid in price discovery and 

provide hedging opportunities for those that generate and sell electricity into these 

markets and those, such as traditional distribution utilities, competitive retail providers 

and large customers, that buy directly from those markets. But like most things in life, 

one can have too much of a good thing or a good thing, but at the wrong time and 

place. Financial trading in the PJM markets is a "good thing." But financial trading in 
91 


PJM's markets cannot be presumed beneficial in all circumstances. Unique design 

aspects attendant to RTO electricity markets can work to prevent realizing the 

theoretical efficiency expected from trading. In these instances, RTOs and FERC must 

work to preclude those trades which, if allowed to continue, would only leak revenue 

from sellers or savings from buyers of physical electricity - offering no commensurate 

efficiency benefit to the system. 

PJM recently filed certain reforms with the FERC for just this purpose: to 

preserve the value that financial trading can offer to PJM's markets while minimizing 

situations where trading siphons off revenues with no corresponding system benefit. 

These reforms should help additionally to reduce those instances, as noted in the Staff 

Memorandum prepared for today's hearing, where FERC's enforcement arm is forced to 

step in to curtail trading that simply exploits market rules offering no real benefit to the 

overall market. 

1. RTO Markets Uniquely Blend Physical and Financial Transactions 

Like other commodities, wholesale electricity is transacted both physically and 

traded financially. And like other financially traded commodities, specialized 

environments, such as exchanges and electronic trading platforms, have evolved to 

facilitate financial trading. For instance, financial electricity is traded on the New York 

Mercantile Exchange (NYMEX), the Intercontinental Exchange (ICE) and Nodal 

Exchange. These exchanges offer futures, options and swaps to trade electricity 

specific to PJM and at multiple locations (or nodes) on the PJM system. These so-called 

"secondary markets" in PJM electricity are not regulated by FERC. They are separate 

from PJM's FERC-regulated markets and affect PJM's markets only very indirectly. 

While these secondary financial markets are not the subject of today's hearing, I 

raise them only to clarify that highly-developed, highly liquid and specialized forums 

exist for those that wish to hedge or speculate on PJM electricity prices outside of the 

PJM market itself. PJM's markets are fundamentally designed to facilitate the dispatch, 

purchase, sale and delivery of physical electricity from power plants to wholesale 

electricity buyers, who in turn sell retail electricity to homes and businesses. 

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92 


In this sense, the auction-based day-ahead and real time electricity markets 

administered by PJM are not unlike a livestock auction- but one where wholesale 

buyers and sellers meet to transact physical electricity instead of say, live cattle. And 

just as is the case with financial electricity, separate secondary markets offered by 

exchanges (like the Chicago Mercantile) provide a place to trade agricultural 

commodities (like feeder cattle futures and options), quite distinct from the physical 

buying and selling that takes place at the livestock auction. 

Wholesale electricity markets, such as PJM's, have one feature not shared by 

the livestock auction in this example, and one that uniquely distinguishes RTOs from 

markets in other physical commodities. Central to the commitment and dispatch 

operations of RTOs is a market designed to allow both physical and financial bids and 

offers. While banks, Wall Street trading houses and speculators do not show up 

alongside farmers, feedlot owners and large food companies at a livestock auction, 

these types of entities can and do show up alongside merchant and regulated power 

plant owners seeking to sell the output of their plants through P JM to municipal, 

cooperative, and private utility companies that buy this output to sell retail electricity to 

homes and businesses. In short, RTO markets provide a unique platform that 

accommodates both physical and financial transactions in an integrated fashion. This 

distinction is important for two reasons. 

First, the voluntary participation of financial traders in PJM's fundamentally 

physical market is premised on an assumption that financial transactions alongside 

physical transactions in the same (as opposed to just in a secondary market) help the 

efficiency of the predominantly physical market. Some question the validity of this 

assumption arguing financial trading of electricity should take place only in secondary 

over-the-counter, exchange and electronic trading markets and not in RTOs. With 

some caveat discussed below, PJM disagrees and believes the construct allowing 

financial participation in its markets is both theoretically sound and its value borne out 

from actual experience. 

Second, the metric for financial traders in PJM is whether in fact their 

participation facilitates and brings efficiency in meeting the market's prime objective -

the commitment, dispatch and delivery of physical electrons from generation to load. 

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PJM, unlike a secondary market platform, at its core does not exist to support financial 

trading. As noted, other forums such as ICE, Nodal Exchange and NYMEX, perform 

this function and provide extensive opportunity for parties to hedge, speculate on and 

arbitrage PJM-specific prices and prices from other RTOs. 

2. The Value Financial Trading Brings To PJM 

Financial trading can add liquidity and contribute to efficient price formation in 

PJM's electricity markets. Financial traders participate in PJM's day-ahead energy 

market through so called "virtual" offers and bids for electricity (known in PJM parlance 

as "incs" and "decs" respectively) and through an instrument known as an Up-ToCongestion ("UTC") transaction. Traders also participate in buying and selling an FTR 

or financial transmission right, which offers the opportunity to hedge or speculate on 

price differentials between two points (or nodes) on the PJM system. 

The theoretical basis to support "inc" and "decs" and FTRs is sound and the 

liquidity and convergence efficiency noted in the Committee Staff's Hearing Memo can 

be demonstrated empirically through analysis of historical price outcomes in PJM. The 

case to support the efficiency proposition of UTC transactions, which to my 

understanding are found only in PJM, is less clear. 

"lncs" and "decs" and FTR's are integral components- not merely optional 

design features- to PJM's day-ahead and real time energy markets. While true that 

traders can realize some of their trading and risk management objectives on secondary 

market platforms, such as Nodal Exchange, ICE and NYMEX, their presence in PJM as 

virtual or FTR traders: 

(i) provides these participants opportunities simply not available or not easily 

duplicated elsewhere, 

(ii) improves the efficiency and price discovery aspects of PJM's energy 

markets, and 

(iii) provides value to other PJM participants in the form of efficient prices and 

tools to build more structured risk management arrangements. 

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3. Recognizing Limits To The Value That Financial Trading Can Bring 

RTO electricity markets are characterized by a high degree of rule and 

regulation; indeed the term "market design" is familiar to those involved in these 

markets. This term describes an elaborate set of rules, which are translated into models 

and algorithms and incorporated into software used by RTOs to execute complex 

mathematical optimizations. These outcomes work to clear markets and price a host of 

energy and energy-related products (known as "ancillary services") in order to produce 

the most economic commitment of generating stations consistent with the 

physical/operational constraints of the transmission and generation network. 

But for today's hearings, the important takeaway is to appreciate the rules, 

models and algorithms that make up "market design" bear significantly on how prices 

are formed. In other commodity markets, recalling the example both of live cattle sold 

at the livestock auction and the feeder cattle futures contract sold on the Chicago 

Mercantile Exchange, prices form more or less where supply meets demand. And 

while true that offers and bids similarly form RTO prices, RTO prices additionally 

depend highly on market design, and the rules, models and algorithms underling this 

design. 

The design structure of these electricity markets means that RTOs and FERC 

cannot accept categorically the proposition that financial trading per se improves 

efficiency by bringing convergence and the benefits of liquidity. Occasionally structural 

aspects of the market design will cause price dislocations, both locational (between one 

node/price point and another) and temporal (between day-ahead and real time). Theory 

might lead one to believe that trading would help arbitrage these price dislocations to 

bring convergence and price discovery. And indeed where electricity is "mis-priced" in 

one place or time relative to another due to a lack of information in the market or 

inaccurate forecasts or assumptions by the RTO or market participants, trading to "arb 

out" these price differences is valuable. But where instead these price differences 

result from structural market design features (rules, models, etc.), no amount of trading 

will "arb out" the price difference. Why? Because in these cases prices will converge 

only with a change to the market design either a rule change or redesigning the 

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models and software clearing the market. Trading this pricing inefficiency does not 

eliminate the inefficiency, it merely profits from it. 

Financial trading itself cannot change rules or models; at best such trading 

highlights a consequence that might not have been understood by market designers. In 

this sense, false arbitrage trading is akin to taking advantage of a broken ATM. But 

more often, market designers cannot correct modeling discrepancies or align the 

differences in rules that lead to price dislocations because they exist for other purposes 

necessary to operation of the physical grid. While FERC has alleged market 

manipulation in certain cases where trading has exploited either design deficiencies or 

necessary design features, the onus in the first instance is on the RTO charged with 

market design to identify and anticipate structurally occurring price dislocations and 

either {i) reform the market design to eliminate the dislocation, or {ii) preserve the 

design for other reasons, but then eliminate the opportunity to trade around this design 

feature. 

4. Recent PJM Reforms Relating To Financial Trading 

PJM has pending before FERC two dockets that offer examples of steps that 

RTOs can and should take to right size financial trading and eliminate trading where 

structural or particular market design features work such that trading inherently cannot 

offer the efficiency benefits that might theoretically be presumed. Revenues in PJM are 

highly contested, both by suppliers questioning the adequacy of PJM prices to preserve 

the physical infrastructure needed for reliable operations and by consumers wary of 

paying more for wholesale electricity than is necessary. Financial trading that siphons 

revenues from PJM markets without offering commensurate efficiency benefits should 

be eliminated. This type of trading represents a "hole in the bucket" that PJM must 

plug by filing rule changes for FERC to approve. 

PJM's pending reform proposals will affect UTC transactions most, "incing" and 

"decing" to a lesser degree, and FTRs not at all. In Docket ER18-86, PJM seeks to 

impose charges on UTC transactions commensurate to charges it already levies on 

other virtual transactions ("incs" and "decs"). The objective is to restore levels of 

traditional virtual trading with a demonstrated record of efficiency benefit, and reduce 

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what, in the past decade, has been a dramatic increase in UTC transactions, whose 

benefits are more questionable. In Docket ER18-88, PJM seeks to eliminate financial 

trading from certain nodes that exist for other market operation purposes, but for 

idiosyncratic reasons, offer financial traders no opportunity to provide added efficiency 

to the system. Trading at these nodes simply taps a hole to siphon revenue out of the 

bucket. 

As noted, some question altogether the unusual presence of financial trading in 

what otherwise is an overwhelmingly physical marketplace - having a Wall Street hedge 

fund manager attend the livestock auction, as it were. Again, as is often the case in life, 

there can be too much of a good thing or a good thing, but at the wrong time and place. 

Financial trading in the PJM markets is a "good thing." But it must be right sized and 

prevented in those limited situations where the market design is such that financial 

trading cannot deliver the efficiency benefit it might theoretically promise. Reforms of 

this sort will preserve the value that financial trading provides to PJM's markets, and 

minimize situations where trading is parasitic and where it attracts the attention of FERC 

enforcement. 

5. Conclusion 

Once again, PJM thanks this Subcommittee for the opportunity today to share 

our thoughts on the role of financial trading in FERC regulated wholesale electricity 

market. We stand ready to assist this Subcommittee as it examines this topic going 

forward. 

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Mr. UPTON. Thank you. 

Last, we are joined by Chris Moser, senior VP of Operations for 

NRG Energy. 

STATEMENT OF CHRISTOPHER MOSER 

Mr. MOSER. Good morning, Chairman Upton, Ranking Member 

Rush, members of the subcommittee, and fellow panelists. My 

name is Chris Moser, senior vice president for commercial operations and all operations at NRG Energy. As such, I am responsible for the physical operation of our power plants as well as the 

purchase and sale of billions of dollars of coal, natural gas, and 

power each year. 

My employer, NRG, is one of the largest owners and operators 

of power plants in the United States. Our portfolio includes conventional plants such as coal, nuclear, natural gas and oil, as well as 

a large renewable fleet of wind and solar generation. NRG also operates a retail business that serves approximately three million retail customers largely in Texas, but also in the eastern States that 

allow retail electric choice. As such, we come at this from both the 

merchant generation side and from the retail providing side. 

As a purely competitive company with no captive ratepayers we 

earn what we make in the markets that we participate in. As such, 

we believe that fair and robust competition in the electric sector is 

the best means of delivering value to consumers. But that comes 

with risk, and management of financial and operational risk is critical to the competitive markets and those participants in the markets. 

NRG relies on a wide variety of tools to manage those risks to 

remain competitive and to reduce the delivered cost of power to 

consumers. Included in this tool chest are a wide array of financial 

products traded within organized energy markets, traded bilaterally between market participants, and through centrally cleared 

exchanges. NRG uses FTRs and virtual transactions every day to 

hedge and deliver affordable power to consumers. 

On the retail side, NRG uses FTRs to hedge against congestion 

charges on the transmission system which allows us to sell power 

to end use customers at predictable prices. By allowing us to protect against unforeseen congestion costs on the transmission system, we are able to offer customers affordable, fixed-price power offerings. Without these products, our company and others would 

have to charge higher prices to manage that increased risk, that 

risk premium. That cost would end up being included in retail 

sales which directly increases consumer costs. 

On the wholesale side, NRG likewise utilizes financial products 

for price discovery and to ensure that our large central station generation receive a predictable price for the power that they produce. 

This includes selling power on a forward basis which allows NRG 

to lock in prices. It also includes purchasing FTRs to perfect those 

hedges and utilizing virtual transactions to move power sales from 

day-ahead market to the real-time market or vice versa. These 

tools are critical to the profitable operation of our power plants and 

to the overall stability of the wholesale competitive markets for 

electricity. 

98 

In conclusion, financial bilaterals, FTRs, and virtual transactions 

all play a critical role in the production and delivery of affordable 

power to consumers. I thank you for the opportunity to appear before the subcommittee and I am happy to help with any questions. 

[The prepared statement of Mr. Moser follows:] 

99 


November 29,2017 

Before the Subcommittee on Energy 

Energy and Commerce Committee 

U.S. House of Representatives Washington, DC 

Testimony of Christopher Moser, 

Senior Vice President for Operations for NRG Energy, Inc. 
100 


Summary: NRG Energy, Inc. ("NRG") is an owner and operator of power plants across 

the United States. We also have a retail business that serves approximately 3 million customers. 

As a purely competitive company with no captive ratepayers, NRG and its shareholders bear the 

risks (and the profits or losses) associated with its participation in the wholesale and retail 

electricity markets. We believe that fair and robust competition in the electric sector is the best 

means of delivering value to consumers. 

Management of financial and operational risk is critical to the competitive markets and 

the participants in those markets. NRG relies on a wide variety of tools to manage these risks 

and reduce the delivered cost of power to consumers. Included in that tool chest are a wide-array 

of financial products traded within the organized energy markets, bilaterally between market 

participants, and through centrally-cleared exchanges. 

NRG uses Financial Transmission Rights ("FTRs") and "virtual" transactions every day 

to produce, hedge and deliver affordable power to customers. On the retail side, NRG uses FTRs 

to hedge against congestion charges on the transmission system, which allows us to sell power to 

end-use consumers at a predictable price. By allowing us to protect against unpredictable 

congestion costs on the transmission system, we are able to offer customers affordable, fixedprice, power offerings. Without these products, our company and others would have to charge 

higher prices to manage the increased risk. This "risk premium" cost would wind up being 

included in retail sales, which directly increases consumer costs. 

On the wholesale side, NRG likewise utilizes financial products to ensure that our large 

central station generators receive a predictable price for the power they produce. This includes 

selling power on a forward basis, which allows NRG (and other generators) to avoid the 

potentially serious financial consequences of unexpected outages on the transmission system by 

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purchasing FTRs and utilizing virtual transactions to move power sales from the day-ahead 

market to the real-time market, or vice-versa. These tools are critical to the profitable operation 

of our power plants and to the overall stability of wholesale competitive markets for electricity. 

Testimony 

Good morning Chairman Upton, Ranking Member Rush, members of the Subcommittee 

and fellow panelists. My name is Chris Moser, and I am Senior Vice President for Operations at 

NRG Energy, Inc. 

Background on NRG and My Role at the Company: 

NRG is one of the largest owners and operators of power plants in the United States. Our 

portfolio includes conventional plants powered by coal, nuclear, natural gas, and oil, as well as a 

large fleet of wind and solar generators. NRG also operates a retail business that serves 

approximately 3 million retail customers, largely in Texas and in Eastern states that allow 

customers to choose their retail electricity provider. Thus, NRG comes at the issues before the 

Subcommittee this morning from both a competitive generating and load serving perspective. 

am responsible for operations at NRG, which includes the physical operation of our power 

plants, as well as the purchase and sale of billions of dollars of coal, natural gas and power each 

year. 

NRG's business is premised on one key concept; that fair and robust competition, and 

not monopoly, is the best tool for providing value to consumers. As a purely competitive 

company with no captive ratepayers, NRG and its shareholders bear the risks and the economic 

consequences- positive or negative- associated with its participation in the wholesale and retail 

electricity markets. As this Subcommittee has heard in previous hearings, some companies are 

seeking corporate bailouts to undo the results of competition in the electricity markets. NRG's 

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position is very different. We urge this Subcommittee to ensure that the organized markets 

utilize competition to drive investment in energy infrastructure, lower costs for consumers, and 

provide reliable electricity to power the economy. 

One important contributor to such competition is ensuring that our markets have effective 

rules for price formation. Another is that policymakers say "no" to bailouts when competition 

produces a different result than some companies might want. Today's foeus is on the third leg of 

the stool -ensuring that companies operating in competitive electricity markets can use financial 

trading and hedging tools to manage risk. This Subcommittee can help ensure that the Federal 

Energy Regulatory Commission focuses on all three of these important contributors to 

competition in our electricity markets. 

Financial Products are a Critical Part to Delivering Low Cost Power to Consumers: 

Financial transactions are an important tool we use every day at NRG. In organized 

markets, electricity prices should include: (i) the cost ofthe underlying commodity; (ii) a 

congestion component, which reflects the value of electricity in varying locations and takes into 

account physical constraints on the transmission system; and (iii) transmission line losses, which 

reflect the fact that some electricity is lost as it flows across a transmission line. As the 

Subcommittee's Hearing Memo noted, "[w]holesale electricity is a volatile commodity with 

prices that can change dramatically throughout a given day ... " This volatility only increases as 

we deliver power into "load pockets," which are typically constrained areas of the transmission 

system where the transmission losses and congestion components of electricity pricing can be 

higher. 

Proper pricing of electricity involves some degree of volatility as market participants 

respond to pricing and other dynamics. High prices signal to consumers that they may wish to 

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reduce their consumption of energy during a period of high prices, and low prices tell generators 

that they should decrease their output. Financial products allow us to manage this volatility and 

deliver reliable, low-cost power to end-use consumers. 

NRG's Sales of Forward Power: 

The organized markets and associated financial exchanges are critical to allowing NRG 

to "hedge" expected production of electricity from our power plants. Forward sales of power 

provide us a predictable stream of revenue from the expected generation capability of our power 

plants, while allowing consumers to lock-in their long-term power costs. For example, entering 

2017, NRG had sold forward 30% of its expected generation capacity for 2017-2020 in the 

Eastern portion of the country. In Texas, the number was even higher, with 46% of our coal 

generating capacity being sold forward in 2017-2020. 

Without access to forward financial markets, NRG would be entirely dependent on spot 

market pricing to determine whether the continued operation of any of its power plants wilt be 

profitable or not. Because forward sales of power are typically based on today's prices, issues 

like wholesale market price formation are a top priority for the company price formation 

effects not only today's revenues, but also those we receive in the future. This is particularly 

true in markets without capacity markets (such as ERCOT) or markets where capacity revenues 

are not established on a competitive long-term forward basis (such as the California ISO, MidContinent ISO, and New York ISO). In such markets, forward sales of power are the best way to 

determine if a particular power plant wilt be profitable in the long run or if a particular capital 

investment is warranted. 

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NRG's Use of Financial Transmission Rights: 

NRG utilizes Financial Transmission Rights, or FTRs, in three primary ways: 1 

Retail Power Sales: 

NRG purchases FTRs to hedge its retail sales of power. In the organized RTO/ISO 

electricity markets, there can be significant differences in the price we: (i) receive for sales from 

our power plants and (ii) pay to purchase power needed to serve our retail load obligations. 

These price differentials result from the fact that NRG's generation resources or power purchases 

are not always co-located with the customers we serve, which exposes NRG to the risk of 

congestion on the transmission system. Electricity costs more to make and deliver in crowded 

(or "congested") areas of the grid, such as large cities or areas that are far from generation. 

NRG utilizes FTRs to manage this risk and provide predictable and stable prices to its 

end-use customers. Specifically, NRG can purchase an FTR along the path between a generating 

facility (or, more likely, a liquid point on the system, usually known as a "hub") and its end-use 

customers. For example, New York City's electric grid is as congested as its roadways. So if 

NRG sells electricity to a customer in the middle of New York City from a power plant located 

in upstate New York, it is likely that the transaction will incur additional congestion charges. 

Without FTRs, it would be difficult to predict exactly how much we would pay in extra 

congestion charges and we would have to include a larger "risk premium" in our prices to 

account for that uncertainty. A higher risk premium directly increases the price paid by end-use 

consumers. Purchasing an appropriate FTR, however, allows the parties to "lock in" those 

congestion charges, eliminating much of the congestion risk in exchange for an upfront payment. 

Of course, purchasing FTRs costs money, which may reduce the profits we would 

otherwise earn. But the tradeoff is that we will not lose large amounts of money if unexpected 

1 While not the focus of my testimony today, NRG also engages in limited speculative FTR trading. 

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congestion appears on the system. Overall, FTRs allow NRG to protect against unpredictable 

congestion on the transmission system, minimize the costs to retail customers, and increase our 

ability to offer customers long-term, fixed-price power deals. 

Wholesale Power Sales: 

FTRs are also critical to the process of selling our generation output to other retailers of 

electricity. For example, NRG often sells power from its power plants on a bilateral basis to 

other companies, who then re-sell the power to end-use consumers. The organized electricity 

markets facilitate these bilateral sales by providing both parties with open access to the 

transmission system and clear, transparent prices. 

Whether the buyer or seller takes the risk of congestion is often a significant negotiating 

point. Sellers of power typically prefer that all risk of congestion (or even outright failure of the 

transmission system) transfer to the buyer at the point where the power plant injects the power 

into the grid. Buyers, on the other hand, typically prefer that the seller maintain the risk of 

successfully delivering the power. FTRs allow either party to manage the risk of transmission 

congestion by buying an FTR. If the sale of electricity is ultimately accompanied by any 

additional congestion costs, then the FTR makes the parties whole for those costs. Thus, FTRs 

provide an "insurance policy" against the risk that congestion will appear on the system and 

substantially alter the economics of the underlying transaction. 

FTRs are particularly important when selling the output of large-scale renewable 

generators, which are often located far from load. In many cases, generators located far from 

load are subject to increased risk of congestion between the point of injection into the power grid 

and the point of delivery to an end-use customer. FTRs protect both sides of the transaction from 

congestion risk, which facilitates stable prices for both buyers and sellers of renewable power. 

7 
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Transmission System Investments: 

FTRs can be a powerful means of attracting additional at-risk capital into the 

transmission system, which is typically dominated by utility investment using captive ratepayer 

dollars. Most organized markets permit non-utilities to pay to upgrade an "element" of the 

transmission system that constricts the flow of power from Point A to Point B. In exchange for 

fronting the capital to make or advance the construction of the upgrade, the investor receives the 

value of any additional power flows across that element, usually in the form of FTRs or related 

products. Thus consumers receive new or accelerated improvements to the transmission system, 

while investors only make money to the extent the new/upgraded transmission improvement is 

actually used. This moves risk from captive customers to private investors, while increasing 

total infrastructure investment. 

NRG's Use of Virtual Transactions: 2 

NRG likewise uses virtual transactions to manage sales from its power plants and to 

manage retail market positions. Virtual transactions are a powerful tool for managing the risk 

inherent in two-settlement electricity markets, where some power sales take place in the dayahead market (the first settlement), and other sales take place in the real-time market (the second 

settlement). Prices can diverge between day-ahead and real-time markets as physical conditions 

on the grid evolve over time. These price differences are critical to the proper functioning of 

electricity markets, and are often caused by changing load forecasts (i.e., as we get closer to realtime, we better understand consumer demand, based on weather and other factors), changes in 

generator or transmission line outages, changing fuel costs, or other factors. 

As a result, it is often more or less advantageous to sell (or purchase) power in either the 

day-ahead or real-time markets. Virtual transactions allow generators to pay a (usually small) 

'As noted above with FTRs, NRG also engages in limited speculative trading of virtual power. 

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fee to "virtually" shift their sales of power from the day-ahead to the real-time market, if 

conditions warrant. 

Conclusion: 

Financial bilaterals, FTRs and virtual transactions all play a critical role in the production 

and delivery of affordable power to consumers. On the retail side, these products provide a 

"hedge" against unexpected congestion charges on the transmission system. On the wholesale 

side, these products ensure that generators receive a predictable price for the power they produce. 

Thank you, again, for the opportunity to appear before the Subcommittee today on these 

important matters. I would be happy to answer any questions that Members of the Subcommittee 

might have. 

9 
108 

Mr. UPTON. Well, thank you. Thank you all. We will now go to 

questions from the Members, I guess. 

The first question I have, Mr. Allen, you indicated in your testimony that—I believe you said—the western alliance did not participate in virtual traders. Is that right? 

Mr. ALLEN. Yes. 

Mr. UPTON. So which States are in that western alliance? 

Mr. ALLEN. It is the western Energy Imbalance Market, so it includes Utah and Nevada, parts of Colorado. It is dispatched as a 

part of the California Independent System Operator, but convergence bidding—that is what they call virtuals in California—is only 

allowed in the California ISO proper. So most of California and a 

little sliver of Nevada is the only place where virtuals are allowed 

to—— 

Mr. UPTON. So by not having that would you say that those folks 

in those States then pay, the consumers, themselves, likely pay a 

higher utility cost, higher electric cost? 

Mr. ALLEN. Higher than they would otherwise with the competition and the liquidity that virtuals add. Yes, sir. 

Mr. UPTON. Let’s see. Ms. Sidhom, in your testimony you explained that financial markets participants increase competition 

and efficiencies in the electricity markets. Can you explicitly state 

how the trading of those FTR instruments makes the markets 

more efficient? 

Ms. SIDHOM. Absolutely. So essentially what is happening here 

is, you know, Dr. Hildebrandt explained these transactions as a 

price swap and that is exactly what they are. FTRs are a price 

swap. It is a fixed for floating. So the load-serving entity gets the 

fixed and a financial entity will take on that floating risk. So they 

are basically shifting risk away from consumers and onto companies like mine that are willing to take on that risk and can manage 

that risk and offer hedging services. 

So when you have all this competition in the market and market 

participants that are willing to bid in an open and transparent auction so you can go into any RTO/ISO Web site and see who got the 

contract in the auction and the price they got the contract, there 

are also multiple rounds systems of these auctions so there is multiple opportunities for load-serving entities to have some price discovery, as Mr. Moser was saying, to then offload some of their risk 

in multiple rounds. 

So essentially what we do is we go in and we provide liquidity 

and price competition to benefit the consumer and shift that risk 

of the volatile market away from them. 

Mr. UPTON. You also said in your testimony that they needed to 

have an upgrade on the hardware and software. 

Ms. SIDHOM. Yes. 

Mr. UPTON. So I mean, where are they in that process? 

Ms. SIDHOM. That is an excellent question. 

Mr. UPTON. Do they understand the problem? I mean do 

they—— 

Ms. SIDHOM. We don’t have a really good answer to that question 

because there is not a lot of transparency as to what software and 

hardware upgrades have been made. We know DOE had a $3 million grant that they gave to the Midwest ISO to improve their dayVerDate Mar 15 2010 13:10 Feb 15, 2018 Jkt 037690 PO 00000 Frm 00112 Fmt 6633 Sfmt 6633 I:\115THCONGRESS\115X81FINANCIALTRADERS\115X81FINANCIALTRADERSWORKING
109 

ahead solve time so essentially so that when generators get committed in day-ahead they have some time to procure the gas. It is 

a gas-electric coordination initiative. 

We really don’t know where those funds went, what the upgrades 

were like, what upgrades are necessary. It is kind of all a big black 

box to us. But what I can tell you is that several of the RTOs and 

ISOs have had a hard time solving their auctions and that is an 

issue for us because that is a risk. They may not solve the auction 

until the settlement period so you essentially have positions on 

that you don’t know what your profits and losses are. 

So that is a big concern. Financial institutions in this country are 

utilizing great technology and they are processing far more information than the RTOs and ISOs are and so is our intelligence community. So we would really like more transparency into what upgrades are necessary and a plan just like any private company 

would plan, OK, over the next 3 years, here is how we are going 

to spend dollars on making technology upgrades. 

Mr. UPTON. Thank you. 

Mr. Minzner, so as you talked particularly in your formal role at 

FERC, have you found that the CFTC and FERC have worked 

pretty well together as it relates to the transactions in terms of 

their oversight role? Are there real squabbles? Are there things 

that we need to know about? 

Mr. MINZNER. I think now their relationship is quite good and 

the agencies have begun to work well together and have been effectively able to coordinate their enforcement programs. I think the 

relationship has waxed and waned. You may be familiar with a 

case several years ago where the agencies ended up litigating 

against each other in the DC Circuit over the scope of enforcement 

authority. 

I don’t think anybody would view that as a desirable outcome, 

but I do think as the leadership of the agencies have worked together, tried to build the relationship, and tried to build relationships at the staff level, many of those issues have passed and I do 

think now the relationship is much stronger and much more effective. 

Mr. UPTON. Thank you. 

Mr. Rush? 

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

Ms. Sidhom, am I pronouncing it right? 

Ms. SIDHOM. Yes. 

Mr. RUSH. Do you believe that FERC currently administers the 

financial trading market in a truly open, transparent, and competitive way that best serves the interests of consumers, and if reforms 

are needed do you believe that they could be accomplished best administratively through a commission, or is congressional action 

needed? 

Ms. SIDHOM. I don’t believe congressional action is needed. I 

think you guys already took the appropriate action in EPAct 2005 

promoting long-term auctions. I think that FERC just needs to actually push the ISOs to go in that direction and again push them 

on the technology initiative. 

The Commission recently looked at PJM’s market design for 

FTRs and they basically said this is working for consumers. It is 

110 

saving them money. It is providing the necessary competition. The 

FERC was very clear there is no redesign warranted. It is very important for these transactions to actually occur within the RTO/ISO 

paradigm because the RTOs and ISOs are the only ones that can 

model the constraints. 

They can say, OK, we have a transmission line that is coming 

online in 3 years from now. We have a unit that is retiring here. 

We can reconfigure the right. So we used to have load from A to 

B. That is where the load concentration was. Now we have it from 

A to C, so we are going to reconfigure the path where we need to 

price that congestion. They are really the only ones capable of 

doing that so it is so important for them to remain as part of the 

paradigm and FERC agrees. They don’t agree with us often, so I 

think it is great that they recently agreed with us. 

Mr. RUSH. Mr. Allen, in your written testimony you say my concerns from a previous hearing regarding the potential for RTOs to 

shut out public interest and participation and you said, and this 

concern should extend beyond consumers to encompass all minority 

interests in the ISO/RTO stakeholder process, including financial 

market participants. 

How would PJMs propose reforms that FERC is currently considering regarding the up-to congestion impact in this process and, 

more specifically, what effect would these reforms have on consumers? 

And Mr. Duane, would you also chime in on that question? 

Mr. ALLEN. Thank you, Ranking Member Rush. I think the UTC 

case that came out of the PJM stakeholder process is a perfect example of the minority interest that is not being protected. If you 

look at the way the voting structure is in PJM for the stakeholder 

process there is five different categories of voting—generation owners, transmission owners, load-serving entities, and financial market participants are one of those as well. Most of the PJM membership it is lumped into what they call the other supplier sector 

which is the sector financial market participants are lumped into. 

And just so you know, if an IPP or an independent power producer is building a power plant, until that power plant goes online 

they are lumped into the other supplier sector. So like I was saying, most of the membership is there. And if you look at how the 

voting occurred in the PJM stakeholder process you had basically 

the utilities voting in one way and then everybody else voting in 

a different way, but it passes because the utilities, you know, have 

a large share of market power in the stakeholder process. 

So I do think reforms are necessary. And, really, when I think 

about a stakeholder process I wonder, you know, I can understand 

having a stakeholder process to determine smaller issue things, but 

when it comes to market design and features, I think, you know, 

a lot of that regulation should not be coming from the utilities or 

from stakeholders. It should be coming from the FERC or from 

Congress, someone other than—it is analogous to the inmates running the asylum. 

Mr. RUSH. Mr. Duane? 

Mr. DUANE. Thank you, Mr. Rush. And I see we have limited 

time so I will try and be very brief here. There is a lot to say, but 

I will just refer you back to the fundamental test at least in our 

111 

belief is that financial trading has to benefit the physical participants and the system as a whole including the consumers and the 

generators, transmission customers. So our stakeholder process 

overwhelmingly voted in favor of these reforms and that covers 

both load interests and supply interests. 

Ultimately, at the end of the day the question of whether these 

transactions bring that kind of value that I am describing will have 

to be resolved by the FERC and that is why they are there, to address those types of controversies. 

Mr. RUSH. Thank you. I yield back. 

Mr. UPTON. Mr. Olson? 

Mr. OLSON. I thank the Chair, and welcome to our six witnesses, 

the special Texas howdy for Chris Moser. I can see NRG’s biggest 

power plant, the Paris Power Plant in Thompson, Texas, from my 

house. That plant generates 36,000 megawatts of power. Four Powder Basin coal trailers come down — trains come down every single 

day, 115 cars. They have four generators of natural gas power and 

four generators with coal power. 

And one coal power is very special, it is called Petra Nova. They 

capture over 95 percent of the CO2 in the process, put in a pipeline, sent it about 60 miles south southeast and get oil out of the 

ground. That is happening right now in my hometown, or in my 

home district of Texas 22. I can see that from Sugar Land, Texas. 

OK, my brag about Texas is over. Let’s get serious. 

Mr. Moser, unlike others on the witness panel today, your company mainly uses financial products like an insurance policy. What 

would happen if these financial products aren’t available? 

Mr. MOSER. The risk that we are otherwise covering with those 

insurance products would either be borne by us and passed through 

to consumers at what we think, you know, what we estimate that 

would be or we would have to find a replacement product which 

would not be administered by the PJM or the ISOs. We would have 

to go to Nodal Exchange or something like that to try and fill it 

somewhere else. 

Mr. OLSON. Is it different for retail and wholesale products, I 

mean differences between those markets? 

Mr. MOSER. So as far as FTRs go, the FTRs as they are constituted and show no difference between a retail or wholesale when 

all you are doing is locking in the congestion basis between two 

points and they are equally effective for hedging either generation 

or retail. 

Mr. OLSON. And how often does a trade go bad and what kind 

of internal oversight do you have to make sure that doesn’t happen? 

So we have a very fulsome risk process and risk policy and a risk 

department which oversees the trades that we put on. And the definition of a trade going bad is probably different between me and 

from one in which a strictly financial participant is. So when I am 

talking about hedging I am literally saying I sold something for 

$30 and I am buying it for $28 and I have locked in $2 of margin. 

So I am indifferent to what the FTR does because it is in effect, 

if I paid $5 for the FTR and it comes in at 4 that looks like a loss 

of 1, but in effect I was getting rid of risk and I am happy because 

I locked in my margin. However, if a purely financial or spec trader 

112 

bought something for 5 and ended up settling for 4 that would be 

the definition of a bad trade. For me it is a hedge, it is not a bad 

trade. It was eliminating risk that I wanted to eliminate. 

Mr. OLSON. Thank you. 

Now let’s bring in Mr. Allen. I understand that each region offers 

different types of financial trading products. From your experience, 

are there certain RTOs who offer unique or particularly successful 

types of financial trading products? If so, please explain. 

Mr. ALLEN. Yes, sir. I do. I think it is called ERCOT. 

Mr. OLSON. I am familiar with ERCOT. 

Mr. ALLEN. What is unique about ERCOT, you know, ERCOT in 

Texas has the most vibrant retail market. And I think part of the 

reason why they have the most vibrant retail market is they have 

the widest availability of financial instruments to allow retail competition. And what we have been advocating for both at FERC and 

in the stakeholder process and now here before you, we would like 

to see a point-to-point product—that is why they call it an 

ERCOT—in all the ISOs. It is an excellent mechanism by which it, 

you know, people can use it, retail load-serving entities can use it 

to hedge. 

The FTR is great. The FTR is a longer-term instrument. It is a 

minimum of 1 month out a number of years. The point-to-point 

product is a daily to real-time product that—it exists somewhat in 

PJM, although they are trying to get rid of it. It is a central for 

retail competition hedging. 

Mr. OLSON. Mr. Moser, do you care to brag about Texas, too, like 

Mr. Allen? ERCOT? 

Mr. MOSER. Yes. So ERCOT is different than a lot of the other 

markets in a couple of fundamental ways. First of all, it is one of 

the few places where we see load growth. There is very little load 

growth in other places. Texas is growing between, depending on 

how you do the math, 11⁄2 and 2 percent. 

Other markets, the other major difference is Texas is an energyonly market. We only make money when we are dispatched and we 

run or when a customer freely chooses for us to be their retail electric provider. You know, we are not a utility in that respect, but 

we also don’t have any capacity payments, which are—call it insurance policies that other assets and other markets have. 

Mr. OLSON. My time has expired. Chairman, I did not mention 

my Astros being the baseball World Series champions. I yield back. 

Mr. UPTON. We are proud of the Astros. 

Mr. McNerney? 

Mr. MCNERNEY. I thank the chairman. I don’t really need to brag 

about California every time I get the microphone, Chairman. 

You know, I found your testimony very enlightening, you know, 

there is so much to learn. It is a complicated market, so thank you 

for coming and giving us your testimony. I would like to start with 

Mr. Hildebrandt. 

Do you consider yourself to be like an inspector general of the 

Cal ISO system, I mean analogous to Federal agencies? 

Dr. HILDEBRANDT. I wouldn’t call it inspector general. It is called 

the independent market monitor. FERC requires each RTO/ISO to 

have one. I think I view our job is to be, you know, analyze the 

data, monitor the markets closely, and call it like we see it, objecVerDate Mar 15 2010 13:10 Feb 15, 2018 Jkt 037690 PO 00000 Frm 00116 Fmt 6633 Sfmt 6633 I:\115THCONGRESS\115X81FINANCIALTRADERS\115X81FINANCIALTRADERSWORKING
113 

tively, for both the FERC, for our management, for the board, and 

for stakeholders as well. 

Mr. MCNERNEY. Well, how would you respond to Mr. Allen’s remarks about the Energy Imbalance Market, his claim that their 

entry to Cal ISO improved efficiency and reduced greenhouse 

gases? 

Dr. HILDEBRANDT. Well, I think he was—the question to him was 

why don’t they have virtual bidding and if they did I guess would 

it lower prices. And the reason they don’t have virtual bidding is 

there’s no day-ahead market in the Energy Imbalance Market. So 

to have virtual bidding you have to have day-ahead market and 

real-time market. There is no day-ahead market in the Energy Imbalance Market, so of course they don’t have virtual trading there. 

Mr. MCNERNEY. So it is not a real clear case. 

Dr. HILDEBRANDT. It is not an issue. You know, if they were to 

join the California ISO and have a day-ahead market they would 

therefore have virtual trading as well. 

Mr. MCNERNEY. One of the things you mentioned was that the 

markets should be organized to allocate auction revenues better. 

You sort of dwelled on that. How would you go about doing that? 

Dr. HILDEBRANDT. Well, I think where—so as I tried to lay out 

we agree that FTRs should be used to allocate congestion revenues 

back to the transmission ratepayers, but we are calling on the ISOs 

to not auction off additional FTRs. And if they did that all the congestion revenues, if there was just no auction it would automatically go back to transmission ratepayers. 

Ms. Sidhom, I think her first point was that FTRs are a way of 

getting congestion revenues back to ratepayers. 

Mr. MCNERNEY. Right. 

Dr. HILDEBRANDT. Well, if you just don’t auction them they automatically go back to ratepayers. And they are doing a very bad— 

the FTRs, if you view it as an instrument for returning congestion 

revenues to ratepayers they are failing miserably at that. In California they are only returning 50 cents on the dollar and in other 

ISOs it is more, maybe 80 cents on the dollar. 

So they are not returning—so our proposal is pretty simple, is allocate FTRs to load-serving entities but then don’t auction off the 

rest, a lot of those congestion revenues to go back ratepayers. If, 

you know, the free market, they are free to buy and sell hedges, 

insurance, if you will. You know, I think that is the role that financial entities they are very creative people. They are good at managing risk. I think they are free to sell price swap contracts to generators such as NRG to hedge their risk. 

And we think that mechanism, a market between, you know, 

willing buyers and sellers is what will give you the correct, efficient, and fair price for I think what has been called, here, insurance policies. 

Mr. MCNERNEY. All right, thank you. 

Mr. Minzner, you sort of dwelled on the cost market and manipulation between the physical market and the sort of financial markets. How would you propose that they be better regulated? Is 

there an important distinction that needs to be made between the 

types of transactions or how would you do it? 

114 

Mr. MINZNER. So I think that is a great question. You know, 

cross-market manipulation has been something the agency has focused on in its exercise of enforcement authority ever since EPAct 

2005, which arose out of the western power crisis largely focused 

in California. I do think FERC has been doing a good job at looking 

at this type of conduct trying to build the analytic and oversight 

tools it needs to be able to detect the conduct and when appropriate 

stop it. 

I do think it is an area where the agency has had to make sure 

it has the data it needs about trading both in the FERC-regulated 

markets as well as the markets regulated by the CFTC and other 

regulators. As you can imagine, for market participants they care 

about the financial positions they hold broadly across all the markets, so it is important for the agency to make sure it can see all 

of those positions. I think it is an area where the agency has been 

succeeding largely, but it is certainly a work in progress. 

Mr. MCNERNEY. I wanted to ask you a question, Ms. Sidhom, but 

I have run out of time, so you will have to take it up with another—I know you wanted to respond to Mr. Hildebrandt’s comments. I yield back. 

Mr. UPTON. Mr. McKinley? 

Mr. MCKINLEY. Thank you very much, Mr. Chairman. Sorry that 

I slip out. Like you said, we have another meeting going downstairs to get back to. 

I missed some of the presentations that you had, particularly Mr. 

Duane’s comments from PJM. But we have had a series of hearings 

in the last year-plus over resiliency and dependability in our grid, 

and so as a result perhaps, I know, I think in your testimony you 

were going to say something about the rule, or the directive coming 

from the DOE over to FERC, how to take care of this. 

One of the arguments that I have heard here so many times in 

committee has been market rates. The market rate should make 

that determination. Well, I am in agreement to some extent, but 

the market rate there should be a difference between market rate 

and dependability rates so that we know when we have a polar vortex or some problem that we know we can count on their being 

power available to folks. 

Because of this pricing system that we have set up, I am concerned about how that could be, how that is going to come into play 

if FERC were to recognize that dependability is just as important 

as market rate. Because on market rate I am trying to find an insurance policy for people that during bad weather they are going 

to have electricity. 

And I know it has been a very divisive issue ever since that has 

come out, and we know that in PJM 20 percent of the power plants 

went down during that period of time. So I am looking for that 

kind of support level in the pricing. 

So, Mr. Duane, if you can give me some, a little bit better explanation, a little bit of how the financial trading tools, how they could 

be impacted if FERC were to come out with some kind of movement which in many respects it would be like an insurance policy 

that would give us some assurance that we are going to have power 

for our grid. 

115 

Mr. DUANE. Right. Thank you, Mr. McKinley. You know, you are 

touching as you point out on a very complex and controversial area 

and it is a fair question to ask right at the outset, are these organized markets returning a price that is fully valuing all aspects of 

the infrastructure that people are relying on to keep their lights on 

and to heat their homes and power their businesses. 

It is a fair question because you can’t assume in these markets 

that just where supply and demand meet you will get the right 

price because, as I mentioned, they are very highly engineered and 

revenues in these markets are very highly contested. You have the 

Department of Energy asking the Commission right now, are these 

markets adequately compensating generators for the full panoply of 

value that they are providing or is there something missing in the 

markets. 

And the gauntlet that has been thrown down when you also consider on the other side of the equation are consumers who are very 

wary of paying any more than they need to for electricity. So we 

have to ask ourselves a question, is the system working? Are the 

prices correct? When you hear the term price formation that is 

really what it means, are prices being formed correctly in these 

very heavily designed markets. 

The point of interplay with the financial trading is if we are not 

getting any efficiency value to assist in these markets from financial trading it really is siphoning revenues off the top. It is a hole 

in the bucket in the system. And the squabbling that is going on 

between load and generators as to whether generation is getting 

paid enough, whether load is paying too much, you know, there is 

another point to be made here is like, well, are we running a system that is fully efficient or are we having some leakage here so 

that the pie is shrinking. 

And I think the point here is there is a lot of value for financial 

trading, but where it isn’t providing value it needs to be curtailed 

and limited, rationalized, so that we do preserve revenues to support the physical participants in the market. 

Mr. MCKINLEY. We also spoke at the last hearing about the 

Longview Power Plant and the impact that has as the most efficient coal-fired power plant in America, but because of the network 

of pricing they are having trouble being able to market their electricity into the system. And so you all were going to get back to 

me. I haven’t heard from anyone yet. 

Mr. DUANE. OK. Well, I apologize for that. I am not familiar with 

the request itself, but we will definitely get back with you on an 

examination of that question. We are very familiar with the Longview Plant. It is a relatively recent coal plant, highly efficient 

waste coal facility. It is located right on top of the Marcellus Shale 

fields so it does face stiff competition from a lot of new combined 

cycle generation. 

But your larger point and I think it is one we agree with at PJM 

is that when you are running a reliable system over the long term 

and you want resiliency, putting all your eggs in one fuel basket 

doesn’t sit well with a lot of engineers and planning people, so we 

are sensitive to the point. 

Mr. MCKINLEY. Thank you very much. I appreciate it. I yield 

back. 

116 

Mr. UPTON. Mr. Peters? 

Mr. PETERS. Thank you, Mr. Chairman. 

I wanted to get back to Ms. Sidhom. So it is always a little difficult because I get, you know, we don’t have a discussion. We sort 

of get six pre-prepared things which are all very interesting, but 

I am trying to connect where the differences are. What I would like 

to see, maybe you could respond to Mr. Hildebrandt’s concern that 

consumers aren’t getting the value of these trades particularly on 

FTRs. 

Ms. SIDHOM. Absolutely. So I think California is unique in that 

it has some of its own challenges with the markets. And the problem is not with the FTR product, the problem is with the market 

design. They have got significant modeling issues so they will clear 

you out of the money all the time. Meaning, let’s say, I will just 

give you an analogy of the equities market to keep it simple. 

Let’s say you want to buy a stock for $30 and your broker comes 

back and says we sold it to you for $60. That happens in California 

all the time. There is something wrong with their pricing model. 

Also, their outage scheduling is a real problem so about over 50 

percent of the time the outages are not submitted in a timely manner to be modeled in the auction and that is what causes a lot of 

what Dr. Hildebrandt is referring to as revenue adequacy, so the 

underfunding of the payments going back to the load-serving entities. 

So it is not the FTR product that is the problem. You absolutely 

need the auction because the auction is how you actually price the 

allocated rights. So essentially, you allocate rights to load-serving 

entities and then how do you get a price for those allocated rights. 

I give you ten stocks, what is the price for them? The price for 

them is obtained when the access capacity is auctioned off. I don’t 

know how else you would be able price them. 

As Vince’s testimony stated, the FTRs were an integral part of 

the market design. They weren’t just an option, they are how we 

provide open access. 

Mr. PETERS. OK. Mr. Hildebrandt, can you respond to that? 

Dr. HILDEBRANDT. OK. Working backwards, it is absolutely incorrect that the allocated, we call them CRRs, FTRs are priced based 

on the auction. They are allocated out, load-serving entities hold 

them, and they get paid the congestion revenues. So by not selling 

them, they get a dollar, the full dollar in congestion revenues 

versus which is on average a price in the auction which is only 50 

cents on the dollar. 

So the ISO allocates to load-serving entities. They keep those. 

They keep the congestion revenues. But then the ISO auctions off 

additional FTRs which sell for 50 cents on the dollar and those are 

bought primarily by financial entities with—and then the payout 

directly reduces the pot of congestion revenues which otherwise 

then gets fully refunded back to transmission ratepayers. 

So, and as California is different, it is true the payout, our analysis shows while it is 50 cents on the dollar it may be more like 

in the 70 or 80 percent range in the other ISOs. But in other ISOs 

across the country, and we have now almost a decade worth of experience that even in the other ISOs ratepayers are only getting 

117 

back about 70 or 80 cents on the dollar of the congestion revenues 

that they are paying for. 

Mr. PETERS. So would there be some margin where they 

shouldn’t get back, do you think they should get back a hundred 

percent? 

Dr. HILDEBRANDT. Well, if entities are buying these as hedges, if 

I am a generator and I am buying them as hedges I would actually 

expect a hedge to go for premium. If I am buying an FTR to take 

away the uncertainty of my congestion, I am a generator, I am 

NRG and I want to sign a deal somewhere for the fixed price and 

I want to get my power there from a generating plant, I should be 

willing to pay a premium. In fact, I think the hypothetical example 

he offered had him losing a dollar on the FTR. 

The fact is these are, they are earning, you know, it is an insurance policy that pays you, you know, a hundred percent on your 

premium. So it is not, so that analogy I think doesn’t work. 

Mr. PETERS. OK. 

Dr. HILDEBRANDT. And, you know, if they were being purchased 

as hedges we would expect the price to be, you know, equal or 

above the congestion revenues. I guess our final point is you don’t 

need the ISO to run that auction because basically we are auctioning off things, insurance that is backed that is subsidized by 

ratepayers. Let the transmission ratepayers decide if they want to 

enter into those contracts. 

Have a market with if you want the ISO to run it, run a market 

if you don’t think, you know, that private trading firms can do that, 

if you have the ISO run it base it on real bids from willing buyers 

and sellers. The financial entities here can offer to sell hedges, the 

generators here can offer to buy hedges, and if you want the ISO 

to run that market that is fine. But don’t ask the transmission 

ratepayers to subsidize that. 

Mr. PETERS. Ms. Sidhom, again, I have 7 seconds. Go ahead. 

Ms. SIDHOM. So there is a risk premium built in because of these 

outages and that is why those dollars are not going back. 

Mr. PETERS. Right. 

Ms. SIDHOM. That is what is really creating the risk for the buyers. And so there is a risk premium that is being built in, but it 

is because of the market design issues. 

Mr. PETERS. It suggests that it is market design. 

Mr. Chairman, I would yield back. 

Mr. UPTON. Mr. Shimkus? 

Mr. SHIMKUS. Thank you, Mr. Chairman. This is a great hearing. 

I want to commend Mr. Peters. It is a great way to engage with 

our panel is to try to find where there is discrepancy and I just 

want to thank him for doing that. I am going to follow a little bit 

along because, you know, we are concerned about the national grid 

and reliability, but we also have our local parochial interests that 

deal with these markets. 

So I would like to start with Mr. Duane on in dealing with when 

the transition from regulated markets to the RTO model, PJM converted many entities from transmission rights to these financial 

transmission rights. How do you protect against additional risk for 

those who have lost their firm transmission rights? Are there entities that end up becoming losers in this transition? 

118 

Mr. DUANE. It is a very fair question. The transition really took 

place quite a few years ago, really over a decade ago, and I think 

it is fair to say the transition from being a firm physical customer 

to having a financial transmission right, which as Ms. Sidhom said 

is a fundamental element of the design structure, that was a fair 

exchange. 

What has happened though is nothing is static. The system 

changes. Load grows in different places. Load disappears in different places. Generation comes, generation goes. That changes the 

typology of the system and, frankly, the FTR was intended to anticipate those changes and provide options. Not just market options, but opportunities for people to designate different pathways. 

People being typically in PJM, these are load-serving entities 

who are trying to manage the risk of congestion or price differential. And as the system changes physically, there are opportunities 

that the FTR provides to reconfigure your pathways to reflect how 

electricity is more realistically flowing to you today as compared to 

where it was, say, 10 years ago. 

But short of transmission infrastructure build, there will be customers that are not as hedged today under this system as they 

would have been 10, 12 years ago. 

Mr. SHIMKUS. Right. And I would speak to expanding our transmission grid to allow those more flexible markets instead of, in essence, kind of dedicated pathways and convoluted systems that 

sometimes we develop. 

I want to go to Ms. Sidhom and Mr. Allen real quick. On financial trading institutions such as yours when you execute financial 

trades with the purpose of making a profit, when your company 

makes money from a financial transaction such as this financial 

transmission right, where does the payment come from? 

Ms. SIDHOM. So we are basically offering a product. The payment 

comes from us offering this product which is where we are basically 

saying, look, we want to take the risk away from consumers, so 

how do we do that? We are natural buyers and sellers to—or we 

are basically the willing buyers and sellers to natural buyers and 

sellers, so that is where the payment is coming from. We are basically offering the other end of that transaction liquidity in the market. 

Mr. SHIMKUS. Mr. Allen? 

Mr. ALLEN. Yes, that is correct. Now there is a differentiation between what our two entities do. They are more FTR-focused. I am 

focused on the day-ahead and real-time. If we add efficiency to the 

market, if we improve the commitment, if we improve the reliability of the system then we make a profit. If we create inefficiencies or we get the day-ahead wrong then we lose money. 

Mr. SHIMKUS. OK, so let’s go to the consumer. Do the consumers 

pay for your payout through their electricity bills? 

Mr. ALLEN. Well, each ISO acts as essentially a clearing broker 

where all of our transactions are cleared. So I put in buy and sell 

orders with PJM, they return whether we make or lose money. One 

thing to point out and I think it is important and it is in my written testimony. What is the load-weighted price of electricity in 

PJM? Wholesale level $29.23, so under $30. What is the retail rate 

119 

in that same area? It is about $110 a megawatt, so wholesale 

prices are cheap. They are really cheap. 

Mr. SHIMKUS. Ms. Sidhom? 

Ms. SIDHOM. Yes. I mean I think we absolutely save the consumer a lot of money. Both in MISO and PJM, they estimate over 

$2.5 billion of savings a year from having these markets in place. 

You know, these are heavy policed markets. The CFTC is looking 

at us, FERC is looking at us. We have market monitors like Dr. 

Hildebrandt looking at us. If FERC thought that we were siphoning money from consumers I think they would have put a stop to 

these transactions a long time ago. 

Mr. SHIMKUS. I have 730,000 people watching me, so—anyway, 

yield back. 

Mr. UPTON. Mr. Green? 

Mr. GREEN. Thank you, Mr. Chairman, for holding the hearing. 

Mr. Moser, in your testimony you talk about FTRs hedge against 

congestion charges for end user, end user consumers. How much 

risk is there from the congestion charges that could potentially be 

pushed to consumers if it weren’t for this product? 

Mr. MOSER. Well, it would be pushed indirectly to them basically 

to the extent that none of the—or very few of—and when I am talking about retail consumers here, I am talking about homeowners 

not the large commercial and industrials who have a more sophisticated way of going about it and tend to shoulder some of the market things directly. But in terms of consumers, if the FTRs didn’t 

exist and we had to price that in then rates would go up. 

Mr. GREEN. In the Texas retail market, of course Texas is different as we say all the time from other markets, but retail market, where do we most often see congestion being an issue and how 

are these products used within the State? 

Mr. MOSER. Yes. We have historically seen a decent amount of 

congestion coming from the western part of the State where you 

have a lot of the wind assets flowing into through congested lines 

trying to get to Dallas and trying to get down into Houston. Texas 

has built the CREZ lines to try and alleviate the into-Dallas area 

portion and then they are working on a Houston import project 

right now to try and alleviate some of those congestions. 

But those are two of the classic ones. Really, anytime you are 

talking about congestion you are talking about, you know, assets, 

generation far away from load pockets and so the load pockets are 

often the congested pieces. 

Mr. GREEN. In the wholesale market when it comes to selling forward on a basis how do these products mitigate potential losses? 

Mr. MOSER. So when we use, and this is different than just 

FTRs, right. I mean, you know, through ICE, which was explained 

by Mr. Minzner and others, we can go out and see where the price 

of next year, next month is trading. We can put positions on, sell 

some of our expected generation and lock, and then go and buy 

some fuel against that lock in what we expect to be our generation 

spread, our profit. 

But those sales are often at hubs where people agree to gather 

and make bulk purchases and sales. What we then would do would 

be go and try and perfect that hedge by using the FTRs to move 

120 

where we have that sale to a location that approximates our generation plant. 

Mr. GREEN. OK. In your testimony you talk about 46 percent of 

the NRG’s coal capacity in Texas from 2017 to 2020 has been forwarded or sold higher than other areas of the country. How does 

that compare to the other generation sources like natural gas at 

NRG? And of course you have a nuclear plant in southeast Texas. 

Is one fuel source forward sold more than another and what plays 

into that? 

Mr. MOSER. Yes. Oftentimes we tend to sell more of our coal 

rather than the gas because the coal tends to be at the money or 

in the money and so we have a large expected value with that. Our 

specific portfolio is a bit like a barbell. We have a lot of coal and 

nuke on one end which runs all the time and then we have a lot 

of old expensive steam gas which doesn’t run very often so we tend 

not to hedge that as much and kind of use that to try and hedge 

against our retail exposure. 

Mr. GREEN. What are some of the differences or difficulties in 

working in markets like ERCOT which lack capacity markets in 

other ISOs where the capacity revenues are established for a longterm forward basis? 

Mr. MOSER. Well, it is easier in a market like PJM where you 

have a 3-year forward look at where the capacity prices are in 

terms of trying to determine the economic viability of your power 

plants. 

Mr. GREEN. OK. 

Mr. Chairman, that is my last question. But to follow my other 

colleague from the Houston area, when your house has six foot of 

water in it and you are so happy to have something to cheer about 

in the World Series. 

So—but again in my last minute, how did NRG deal with some 

of the problems we had? I heard that for example the coal plants 

had to shut down because the coal was so wet that natural gas was 

still there and of course the nuclear plant continued to produce. 

Mr. MOSER. The South Texas Project stayed online throughout 

Hurricane Harvey. We did run into problems at a couple of gas 

plants in the Greens Bayou which is in the northeastern corner got 

flooded. Cedar Bayou which is down near the ship channel was at 

one point we thought was going to get flooded. What we did was 

basically we brought three shifts of people in—cots, MREs—and 

prepared to ride out the storm, in effect. 

But what you heard about Parish was absolutely correct. We did 

have at one point those coal plants—look, coal doesn’t move up conveyors very well when it is liquid, it just kept running down, so we 

had to switch over to gas on those and we also brought the gas 

plants up. So I think at our low point we were in the 70 or 75 percent availability across our fleet in Texas. Limestone is far enough 

north that it wasn’t impacted, but. 

Mr. GREEN. OK. Thank you, Mr. Chairman. 

Mr. UPTON. Mr. Griffith? 

Mr. GRIFFITH. Thank you, Mr. Chairman. 

Dr. Hildebrandt, Mr. Shimkus asked some questions earlier of 

Mr. Allen and Ms. Sidhom, and you heard their answers. In particular, Ms. Sidhom said if there were real problems on where their 

121 

profit comes from, if it was negatively impacting consumers that 

you would be all over them. So I am going to give you a chance 

after you have heard their answers, what say you? 

Dr. HILDEBRANDT. Well, we are calling for this, and actually the 

independent market monitor in PJM has been doing this for 3 

years. So the market monitors whose job, who have the data and 

the information, whose job it is to look at these kind of things, in 

fact, are calling this out and providing the kind of analysis we are 

providing that is showing, you know, ratepayers are getting only a 

fraction of the dollars back from the FTR auction that they would 

otherwise get. So we are here. That is why I am here today. 

Mr. GRIFFITH. What I am hearing from these folks, and I don’t 

know a lot about this product so I am not taking sides, but what 

I am hearing is most everybody seems to think that this in the end 

makes sure the consumers have power and that they are getting 

a fair deal because these folks are making it more efficient. 

And all they are doing from what I gather in interpreting their 

statements all they are doing in most cases is taking a portion of 

the savings that go to the consumers and that is where they make 

their profit by figuring out how to make the system more efficient. 

Do you disagree? 

Dr. HILDEBRANDT. Yes, I absolutely disagree. Part of the issue 

here, we have two very different products being discussed here 

today. There is the virtual trading and I believe the benefits that 

Ms. Sidhom cited, I believe, is somebody’s estimate of what virtual 

trading may have saved. That is very different. 

Virtual trading is our trades between willing buyers and sellers. 

When the ISO clears the virtual that is cleared as part of an energy market which is a market between willing buyers and sellers. 

In that kind of market there can be value from that. However, in 

the FTR it is a very different product. It is an auction. It is not 

an actual market. They are auctioning these things off for 50 cents 

on the dollar. 

In terms of the congestion revenues they are not providing any 

value in terms of, you know, they are siphoning off money which 

I think otherwise could be used to offset the costs of investments 

in the physical system, physical generating plants and physical infrastructure. So I think in that sense they are siphoning money out 

of the system without increasing efficiency in a way that ultimately 

can hurt reliability because it, you know, it does decrease, you 

know, kind of the money that can be used to improve the transmission system at a reasonable price to consumers. 

Mr. GRIFFITH. So what do you think we should do to solve the 

problem as you see it? 

Dr. HILDEBRANDT. Well, as I have said, I think we continue with 

the allocation of FTRs to load-serving entities. That includes direct 

access customers who, you know, are buying power through retail 

choice. But then stop the practice of having ISOs auction off FTRs 

backed by congestion revenues that otherwise go to load-serving 

entities. Stop that auction. 

I think at that point my position is I think ICE, you know, you 

heard the gentleman describe how ICE it is a private company exchange. They provide long-term contracts for gas, for energy. You 

know, let the markets work. Again these gentlemen, Mr. Allen and 

122 

Mr. Moser can deal through ICE or bilaterally as far as selling a 

hedge at the appropriate price. That is what they are good at. 

If policymakers really think ISOs, that the free markets can’t 

work there and ISOs need to step in, then do that through an FTR 

market that only clears bids from willing buyers and sellers, so 

only if load-serving entity bid into that market to sell a hedge 

would they be exposed to having to sell an FTR. 

Mr. GRIFFITH. All right. Now the dilemma that we have is we 

only get 5 minutes for questions. Mr. Allen, do you want to respond 

to any of the comments that were made? I probably won’t have 

time for you, Ms. Sidhom, to get back in, but maybe somebody else 

will give you a minute. 

Mr. ALLEN. I am glad we agree the virtuals are good. As far as 

the other stuff what I would advise, there are many market monitors throughout the country. Not all of them agree with the position that Dr. Hildebrandt has. Any as sort of analysis that FERC 

or you guys see about the value or the lack of value of FTRs coming 

from one market monitor or another, all I ask have it peer-reviewed. There needs to be some sort of peer review of anybody’s 

analysis so that, you know, and market monitors have a tremendous amount of power and their analysis should be peer-reviewed. 

Thank you. 

Mr. GRIFFITH. And I guess you all can appreciate that this is not 

our field or at least most of us up here, and we are just trying to 

get the facts to make sure the American consumers are getting the 

best deal that they can get. And with that I yield back. 

Mr. UPTON. Mr. Johnson? 

Mr. JOHNSON. Thank you, Mr. Chairman. I appreciate the opportunity. And thank the panel for being here this morning. You 

know, the FERC chairman, Neil Chatterjee, recently stated that 

one of the FERC’s top priorities moving forward will deal with de 

novo reviews. As I am sure some of you are aware, the majority 

of the current court cases surrounding FERC’s interpretation have 

gone on for years. 

Mr. Allen, do you have any thoughts on how FERC should address this? 

Mr. ALLEN. I would think that something along those lines, de 

novo review, is probably best left to the courts to decide. It is not, 

you know, I am not a lawyer, I am not, so I really can’t offer you 

a good opinion on it other than I think it is probably, you know, 

let the courts figure it out. 

Mr. JOHNSON. OK. Ms. Sidhom, do you have any thoughts? 

Ms. SIDHOM. Absolutely. And I think that Chairman Chatterjee 

addressed that issue because FERC has lost on it multiple times 

in court now. We all want a robust enforcement program. That is 

really important for us. We need a cop on the beat. Nobody wants 

to participate in a market that is not being heavily policed, especially such a volatile market. 

So, but what we really want is an efficient enforcement process 

and I think that the courts are making the absolute right decision 

on de novo review. 

Mr. JOHNSON. OK, all right. Now maybe some of this has already 

been covered so I apologize if you feel we are being redundant here. 

123 

But we have heard from Dr. Hildebrandt regarding his thoughts on 

FTRs. Mr. Duane, what are your thoughts? Do you have any? 

Mr. DUANE. You know, I think he is asking a question that is a 

legitimate question to ask. I think it is always the right question 

to ask, because at the end of the day as I said several times here 

this morning, and I don’t mean this to disparage the financial participants, but they are there to serve a purpose and that is to make 

sure that the physical participants and, in particular, the consumer 

at the end of the day are getting the best deal possible out of these 

markets. That is what the fundamental design mission is. 

And I think they can bring that benefit, but it has to be scrutinized. So the questions about the design of the market, they get 

pretty arcane when you are looking at the allocation of FTR revenues and I honestly don’t think I can add anymore to that. 

But the litmus I kind of use is if I see real risk management, if 

I see someone speculating and taking risk off the table, if I see 

them hedging, those are good types of financial transactions and 

people should be entitled to earn a return for providing those services and customers who pay a premium to get that insurance 

should feel comfortable about that. 

Where I get more concerned is where there is arbitrage which 

should bring convergence among prices, but I don’t see it actually 

happening. And that is really where I am coming from at PJM is 

a concern that at that point we do have a siphoning problem, we 

do have a hole in the bucket. I think FERC can separate the babies 

with the bath water and we can put in place rules to do that. 

As far as the FTR market goes, I am just not at a point to say 

that is an example of one of those types of problems. 

Mr. JOHNSON. OK. Mr. Shimkus began to address this as well. 

Monitoring Analytics, the independent market monitor for PJM, 

found in the most recent State of the Market Report that—and I 

quote. It is not clear in a competitive market why financial transmission right purchases by financial entities remain persistently 

profitable. In a competitive market it would be expected that profits would be competed away. 

Do you agree with this statement, and if not, why not? 

Mr. DUANE. No, I do agree with that statement. I am not sure 

it is a fair characterization of what is going on in PJM but, theoretically, yes, a competitive market should show over time a balance. And if there is a persistent asymmetry and what I think our 

market monitor is saying is that his observation over a period of 

time is that there is a persistent asymmetry and FTR traders have 

made money rather consistently. 

I am not sure factually that is correct and I would want to look 

into that further, but if that is correct it is the kind of yellow flag 

that says maybe there is something structural in this complex market design that needs to be examined so that we do have a more 

symmetrical outcome. 

Mr. JOHNSON. OK, all right. 

Thank you, Mr. Chairman. I yield back. 

Mr. UPTON. The Chair would recognize Mr. Flores. 

Mr. FLORES. Thank you, Mr. Chair. And I appreciate this hearing 

and appreciate the witnesses participating today. It has been very 

informative. 

124 

One of the principal reasons we have hearings like this is so that 

we as policymakers can determine how involved we should be or 

not be in terms of trying to make sure that these markets work 

correctly. So my first question is this. What potential market regulatory reforms should Congress and FERC be considering in order 

to improve market benefits associated with financial trading? 

So I would start with Ms. Sidhom. Can you share your thoughts? 

And try to do it quickly if you can. 

Ms. SIDHOM. Yes, absolutely. We need long-term auctions just 

like you guys mandated in the Energy Policy Act of 2005. Those 

are integral to provide a forward price signal. 

I also kind of want to address just a few comments that Mr. 

Hildebrandt made. California just put out a report negating a lot 

of the things that he said about FTRs, so its own ISO is not in 

agreement with him. They specifically say there are market design 

issues that they need to fix. So one of the reforms we really need 

is better outage scheduling and I touch on that in my testimony. 

So, essentially, if I am a transmission owner and I don’t plan out 

my outage, I should have to pay the costs that are incurred to the 

system for not planning out that outage. And New York employs 

that very practice and they save a lot of money. They have very 

few unplanned outages. That and technology reform, I think, really 

needs to occur. 

I mean we have certain ISOs where some of their modules don’t 

even work with like Chrome. They work with Internet Explorer but 

old versions of it, like we are really behind in technology. 

Mr. FLORES. OK. Mr. Allen? 

Mr. ALLEN. Real-time congestion hedge like exists in ERCOT, I 

would love to see that. We need to see that. It is necessary. It is 

essential for retail competition. 

Mr. FLORES. OK. Mr. Moser? 

Mr. MOSER. I would say there is plenty of things on the FERC 

docket already in terms of the different price formation dockets 

that they have been sitting on for years that we could move forward with immediately, some of the minimum offer price rules and 

et cetera. So there is plenty of stuff for them to do. 

Mr. FLORES. OK. I would ask you to supplementally follow up 

and tell me what the top three or four are, if you would. 

Mr. ALLEN. Happy to. 

Mr. FLORES. Mr. Allen, also in your testimony you stated that 

competitive markets should be allowed to operate with minimal 

Government intervention such as out-of-market subsidies. If that 

intervention occurs, how is financial trading affected and do you 

have any recent examples? 

Mr. ALLEN. If you have an out-of-market payment going to a certain class of generation assets it will distort market outcomes. 

Mr. FLORES. Sure. 

Mr. ALLEN. I think what is important is if there are certain 

externalities that are not being looked at that aren’t being valued, 

whether it is carbon or reliability or so forth, I would ask that they 

be placed into the market so the market can respond to it and you 

don’t distort market outcomes. 

Mr. FLORES. OK. 

125 

Mr. Minzner, in terms of enforcement of financial trading you 

stated that financial markets inevitably move much faster than 

regulators. I think we all know that about this town. Is there anything Congress can do to ensure that FERC can remain nimble and 

to be able to evaluate new offerings of increasingly complex financial products? 

Mr. MINZNER. So I think that is a great question, Congressman. 

I think largely it has been a success. I think Congress has, when 

problems have arisen in the energy markets, taken appropriate action—EPAct 2005 is a classic example of that—but also left it to 

the agency recognizing the complexity of these markets to adjust 

them as necessary as new products have developed. 

It is not just that the markets are complex. They differ regionally. As you have heard, PJM is quite different from California and 

they are both very different from Texas. That has been a model 

that I think has been largely successful, but I really do think it is 

up to the agency to be constantly be reevaluating the structure of 

the market and the products that are available. 

Mr. FLORES. Thank you, Mr. Chairman. I am going to yield back 

a minute to you. 

Mr. UPTON. The Chair would recognize Mr. Barton. 

Mr. BARTON. Thank you, Mr. Chairman, and you and Mr. Rush 

for this hearing. 

I have not really followed the electricity markets for a number 

of years, so I am trying to get my hands around what a virtual 

transaction is. I don’t know who to ask, I guess Mr. Moser. Are 

these transactions that are called virtual transactions, are they in 

and out the same day transactions? 

Mr. MOSER. Yes. To the extent that the ISOs, if you put aside 

the FTR auctions, are running simply a day-ahead auction for 

power delivery tomorrow, then what the virtual transactions do is 

allow—so when I offer my plants in, you know, we will take Joliet 

6 and we will say it is a $35 unit and we will offer that in to PJM 

in the market, and then if PJM needs $35 or higher power at that 

point I will get a commitment that I then have to run to for the 

next day and I will get paid 35 for it. 

Mr. BARTON. Well, that sounds like a real transaction. 

Mr. MOSER. That is a real transaction. But a virtual transaction 

would be if, you know, if a financial participant put in an offer at 

35 and it looks just like generation in terms of going into the stack, 

it can get chosen and then basically what they have done is they 

have sold 35 in the day-ahead market. They are going to get $35 

times however many hours times however many megawatts, and 

then when they don’t deliver anything the next day because it is 

virtual—and this doesn’t come as a surprise to the ISOs. The ISOs 

know what is virtual and what is real—then that settles against 

whatever the real-time price is. 

So they basically have, they get paid 35 and then they are going 

to pay back to the ISO whatever the real-time average is for those 

same megawatts for that same timeframe, and it may be plus and 

it may be minus. 

Mr. BARTON. So they have to deliver but they don’t have to 

produce; is that—— 

126 

Mr. MOSER. Well, in effect, they are taking the financial obligation of delivering, you know, no one expects virtuals to deliver so 

make no mistake there. There is no chicanery there. But they are 

basically a way of taking a position day-ahead against the real-time 

sell. 

Mr. BARTON. But when a financial participant sells power at $35 

a megawatt hour—— 

Mr. MOSER. Day-ahead. 

Mr. BARTON [continuing]. For tomorrow delivery—— 

Mr. MOSER. Yes. 

Mr. BARTON [continuing]. Sometime that day, do they take a position where they go in and buy, get a commitment to provide that 

power tomorrow at a lower price? 

Mr. MOSER. Well, they may have, they may be doing that because they have a longer term position on that the ISO is not 

aware of. But generally speaking and in its simplest form, they 

have said I am willing to sell $35 power because I think the price 

tomorrow is going to be less than that and they are willing to take 

that risk on what that is for tomorrow’s price. 

Mr. BARTON. I guess the gentleman from California who kind of 

monitors this, are these virtual transactions helpful or hurtful to 

the real-time delivery of power and the pricing of power? You 

know, because California as we remember—some of us old-timers— 

10 or 15 years ago, you had the perfect market, you thought, and 

it all went to pot. 

Dr. HILDEBRANDT. OK. Well, our market is working pretty well 

now, I think, Ms. Sidhom’s comments notwithstanding. And so, you 

know, again you really need to differentiate. I have been talking 

today about financial transmission rights so, but you are asking me 

then about virtual. 

Mr. BARTON. I am just trying to understand. 

Dr. HILDEBRANDT. Sure. 

Mr. BARTON. Because I don’t think the public understands it. 

Dr. HILDEBRANDT. We have them in our market. We think they 

can be beneficial to help kind of to help converge the day-ahead 

and real-time prices especially when you have a lot of renewables, 

so they can be beneficial. Unfortunately, they can be used also to 

manipulate the market. We have had cases like that. And specifically, you know, there are now cases, public cases, where that virtual trades have been used to manipulate prices that then increase 

payments that entities who have boughten firm transmission rights 

have. 

So there is again have been some issues with cross-market manipulation. If you stop the auctioning of the firm transmission 

rights, I think then that would remove the issue of cross-market 

manipulation between the virtual bidding, which we are not proposing to get rid of in California, and can add value and again is 

based on bids from willing buyers and sellers as opposed to the 

firm transmission rights which are distinctly different. 

Mr. BARTON. OK. Mr. Chairman, my time has expired. Thank 

you for the courtesy of allowing me to ask them. 

Mr. UPTON. Yes. With that if no other Members have further 

questions we will adjourn. Thank you very much. 

127 

Oh, and we are going to put something in the record. I am going 

to ask unanimous consent to put in a letter from Monitoring Analytics into the record. 

[The information appears at the conclusion of the hearing.] 

Mr. UPTON. And with that, we stand adjourned. Thank you. 

Thank you. 

[Whereupon, at 11:53 a.m., the subcommittee was adjourned.] 

[Material submitted for inclusion in the record follows:] 

PREPARED STATEMENT OF HON. GREG WALDEN

This is the eighth hearing in our committee’s ongoing Powering America series. 

Today, we will explore the effects of financial trading in the Nation’s wholesale electricity markets. I look forward to hearing from our panel of witnesses to better understand how financial transactions can improve the efficiency of the energy markets, as well as efforts to protect consumers from improper trading activity in energy markets. 

Electricity is intrinsically different than other commodities, as electricity is produced and consumed instantly. Although energy storage technology is becoming 

more economically feasible, it is not yet cost-competitive at a utility scale. The inability to store electricity means supply and demand must constantly be balanced 

in real time. In turn, the instantaneous nature of electricity delivery and consumption can result in volatile energy prices. 

Generators and load serving utilities can protect against price volatility by fixing 

the price of electricity for delivery at a future date by using various financial instruments such as a Financial Transmission Right (FTR). Today’s hearing gives us the 

opportunity to learn more about how these FTRs and other virtual financial transactions fit into today’s electricity markets. 

Financial trading within electricity markets is complex and highly technical in nature. These financial products can improve the efficiency of electricity markets by 

increasing liquidity, mitigating market power, and improving the formation of energy prices, all of which can result in low-cost electricity for consumers. 

We must balance these benefits against a history that includes bad actors who 

have utilized complicated trading strategies to engage in manipulation schemes in 

these energy markets. As I have said many times before, the American consumer 

always comes first. Consumers have come to expect competitive and efficient electricity markets that deliver affordable and reliable power. 

PREPARED STATEMENT OF HON. FRANK PALLONE, JR. 

Today we are examining the role financial trading plays in our Nation’s electricity 

markets. This is a fairly technical, yet important aspect of the management of energy delivery, and it is certainly worthy of greater scrutiny. 

Under the Federal Power Act, the Federal Energy Regulatory Commission, known 

as FERC, oversees electricity markets and the physical and virtual products traded 

within them. FERC specifically authorizes energy market participants’ physical and 

virtual trading under tariff-based rules and protocols. 

Financial tools, which include things like derivatives and financial transmission 

rights, can play a positive role in electricity markets. They do this by providing liquidity, by helping participants to hedge risk associated with a volatile commodity 

and by mitigating market power distortions. This makes for a more efficient market 

and, ideally, lower prices for consumers. 

However, financial instruments can also create opportunities for bad actors to engage in market manipulation -and that is something that has been and continues 

to be of concern to me. I am particularly concerned about large banks and financial 

institutions that participate in the market purely to seek profit. Some of the biggest 

market manipulation cases taken by FERC involve big banks like JP Morgan Chase, 

which agreed to a $410 million settlement in 2013. Similarly, Barclays recently settled a market manipulation action brought by FERC for $105 million, and no longer 

engages in any trading transactions. 

Electricity is a commodity unlike any other, both in physical terms and in terms 

of its importance to our everyday lives. While I do understand the benefits these 

financial tools can provide consumers, producers and transmitters of electricity, I remain skeptical of the role that pure traders and big banks play in this market. At 

128 

a minimum, we must have strong standards and vigorous enforcement against market manipulation to ensure reasonable rates for consumers. 

I want to thank our witnesses for participating today and yield the balance of my 

time. 

129 


Monitoring 

Analytics 

VIA EMAIL 

November 27, 2017 

Honorable Fred Upton 

Chairman, Subcommittee on Energy 

2125 Rayburn House Office Building 

Washington, D.C. 20515-6115 

Honorable Bobby L. Rush 

Ranking Member, Subcommittee on Energy 

2125 Rayburn House Office Building 

Washington, D.C. 20515-6115 

Monitoring Analytics, LLC 

2621 Van Buren Avenue, Suite 160 

Valley Forge Corporate Center 

Eagleville, PA 19403 

Phone: 610-271-8050 

fax: 610-271-8057 

Re: Hearing of November 29. 2017, re role of Financial Participants in Wholesale Power 

Markets 

Dear Sirs: 

I am the Independent Market Monitor for the PJM wholesale power markets. I do not speak for 

PJM. The role of the independent market monitor, as defined by FERC and included in the PJM 

tariff, is to help ensure that the PJM markets are competitive by proposing market rules that 

incent competition, by monitoring for the exercise of market power and by reporting on the 

markets to regulators and market participants. 

In an LMP market, the lowest cost generation is dispatched to meet the load, subject to the 

ability of the transmission system to deliver that energy. When the lowest cost generation is 

remote from load centers, the physical transmission system permits that lowest cost generation 

to be delivered to load. Prior to the introduction of LMP markets, firm transmission customers 

who paid for the transmission system through rates received the low cost generation. 

After the introduction of LMP markets, financial transmission rights (FTRs) were introduced to 

permit the loads which pay for the transmission system to continue to receive those benefits in 

the form of revenues which offset congestion to the extent permitted by the transmission 

system. Financial transmission rights and the associated revenues were directly provided to 

loads in recognition of the facts that loads pay for the transmission system which permits low 

cost generation to be delivered to load. Another way of describing the result is that FTRs and 

the associated congestion revenues were directly provided to loads in recognition of the fact 

that load pays locational prices which result in load payments in excess of generation revenues 

which are the source of the funds available to offset congestion costs in an LMP market. 

Congestion is defined to be load payments in excess of generation revenues. Congestion 

©Monitoring Analytics 2017 l www.monitoringanalytics.com 
130 


Honorable Fred Upton and Honorable Bobby L. Rush 

November 27, 2017 

Page 2 of2 

revenues are the source of the funds to pay FTRs. In an LMP system, the only way to ensure 

that load receives the benefits associated with the use of the transmission system to deliver low 

cost energy is to use FTRs, or an equivalent mechanism, to pay back to load the difference 

between the total load payments and the total generation revenues. The only way to ensure that 

load receives the benefits associated with the use of the transmission system to deliver low cost 

energy is to ensure that all congestion revenues are returned to load. Congestion revenues are 

defined to be equal to the sum of day ahead and balancing congestion. FTRs are one way to do 

that. 

Effective April 1, 1999, FTRs were introduced with the LMP market, there was a real-time 

market but no day-ahead market, and FTRs returned real-time congestion revenue to load. 

Effective june 1, 2000, the day-ahead market was introduced and FTRs returned total congestion 

including day-ahead and balancing congestion to load. Effective June 1, 2003, P)M replaced the 

direct allocation of FTRs to load with an allocation of Auction Revenue Rights (ARRs). The load 

still owns the rights to congestion collected under this system, but the ARR construct allows 

load to either claim the FTRs directly (through a process called self scheduling), or to sell the 

rights in the FTR auction in exchange for a revenue stream based on the prices of the FTRs. 

Under the ARR construct, all of the FTR auction revenues should belong to the load and all of 

the congestion revenues should belong to those that purchase or self schedule the FTRs. 

The current ARR/FTR design does not serve as an efficient way to ensure that load receives all 

the congestion revenues or has the ability to receive the auction revenues associated with all the 

potential congestion revenues. Total ARR and self scheduled FTR revenue offset only 86.5 

percent of total congestion costs including congestion in the Day-Ahead Energy Market and the 

balancing energy market for the 2015/2016 planning period. 

The goal of the ARR/FTR design should be to return 100 percent of the congestion revenues to 

the load. But the actual results fall well short of that goal. The current allocation of congestion 

revenue resulted in a total of $1,714.8 million in unreturned congestion revenue to ARR holders, 

and a 73.9 percent congestion offset, over the last seven planning periods. 

Sincerely, 

Joseph Bowring 

Independent Market Monitor for PJM 

©Monitoring Analytics 2017 l www.monitoringanalytics.com 
131 


GREG WALDEN, OREGON 

CHAIRMAN 

ONE HUNDRED FIFTEENTH CONGRESS 

FRANK PALLONE, JR., NEW JERSEY 

RANKING MEMBER 

<!ongrt5'5' of tbt mntttb ~ta.tt5' 

:U,ou~e of ~epre~entatibe~ 

COMMITTEE ON ENERGY AND COMMERCE 

Mr. Wesley Allen 

CEO 

Red Wolf Energy Trading 

3600 Camp Mangum Wynd 

Raleigh, NC 27612 

Dear Mr. Allen: 

2125 RAYBURN HousE OFFICE BuiLDING 

WASHINGTON, DC 20515-6115 !2021 225-2$27 

(202)225-3641 

December 19, 2017 

Thank you for appearing before the Subcommittee on Energy on November 29, 2017, to testity 

at the hearing entitled "Powering America: Examining the Role of Financial Trading in the Electricity 

Markets." 

Pursuant to the Rules of the Committee on Energy and Commerce, the hearing record remains 

open for ten business days to permit Members to submit additional questions for the record, which are 

attached. The format of your responses to these questions should be as follows: (I) the name of the 

Member whose question you are addressing, (2) the complete text of the question you are addressing in 

bold, and (3) your answer to that question in plain text. 

To facilitate the printing of the hearing record, please respond to these questions with a 

transmittal letter by the close of business on Tuesday, January 9, 2017. Your responses should be mailed 

to Allie Bury, Legislative Clerk, Committee on Energy and Commerce, 2125 Rayburn House Office 

Building, Washington, DC 20515 and e-mailed in Word format to Allie.Buryiulmail.house.gov. 

Thank you again for your time and effort preparing and delivering testimony before the 

Subcommittee. 

Sincerely, 

cc: The Honorable Bobby L Rush, Ranking Member, Subcommittee on Energy 

Attachment 
132 


January 9, 2018 

The Honorable Fred Upton, Chairman 

Committee on Energy and Commerce 

Subcommittee on Energy 

2125 Rayburn House Office Building 

Washington, D.C. 20515-6115 

Wesley Allen 

CEO 

Red Wolf Energy Trading 

3600 Camp Mangum Wynd 

Raleigh, North Carolina 27612 

On Behalfofthe Financial Marketers Coalition 

Re: November 29, 2017 Hearing, Response to Additional Questions for the Record 

Dear Chairman Upton: 

Thank you for the opportunity to testify before the Subcommittee on Energy of the 

Committee on Energy and Commerce of the U.S. House of Representatives on Wednesday, 

November 29, 2017 at the hearing entitled, "Powering America: Examining the Role of Financial 

Trading in the Electricity Markets," and for the opportunity to address additional questions. 

Attached are my responses to those additional questions per your letter dated December 

19, 2017. Please accept my thanks to you, your fellow Subcommittee members, and your Staff 

for your time and consideration. Should you have any questions with regard to the attached, 

please do not hesitate to contact me. 

Sincerely, 

Wesley Allen 

cc: The Honorable Bobby L. Rush, Ranking Member, Subcommittee on Energy 

Attachment 

{W6484S64.2} 
133 


Additional Questions for the Record 

The Honorable Fred Upton 

1) What potential market or regulatory reforms should Congress or FERC be considering 

in order to increase the market benefits associated with financial trading? 

Answer: 

• Development of a Real-time congestion hedge in all markets 

• Restructuring of the stakeholder process in the ISO/RTO markets to better protect 

minority interests 

• Require data provided by ISOs and market monitors to stakeholders and FERC to be 

peer-reviewed 

• Expedited completion ofFERC's Notice of Proposed Rulemaking on Uplift Cost 

Allocation and Transparency 

Product development. Wholesale markets benefit from a diverse toolbox of financial products 

available for all market participants to assist them in efficiently managing their positions. 

Financial products in ISO/RTO markets include virtual energy products, consisting of the 

Incremental Offer (INC) and the Decremcntal Bid (DEC), and virtual transmission products such 

as the Financial Transmission Right (FTR) and the Real-time Congestion Hedge. 1 Virtual 

products allow market participants to reflect in the Day-ahead market the conditions expected in 

Real-time, identifying system conditions so that market operators can make more efficient 

decisions. Forecasting system conditions with virtual products can help produce price outcomes 

that are closely aligned between the Day-ahead and Real-time markets, converging prices as well 

as unit commitment and dispatch. In other words, financial products assist with more accurate 

and granular price formation. Ultimately, price convergence and improved overall price 

formation in the wholesale markets produces lower prices to ultimate consumers. 

Virtual transmission products are congestion hedging tools that can be utilized by any market 

participant to manage risk associated with forward contracting. Having this financial product 

available would particularly assist in hedging variable retail load. Congestion hedging products 

create benefits for both the market participant holding the forward contract and the market 

operator, by providing incentives to participate in the Day-ahead market, providing price 

transparency and efficiently pricing congestion, and signaling to the ISO/RTO when 

transmission capacity investments are needed. Congestion hedging mechanisms include the Upto Congestion transaction and the Financial Transmission Right in PJM, as well as FTR 

equivalent products in MISO, NYISO and CAISO, and products similar to the UTC, including 

the Point-to-Point Product in ERCOT and products under development in MISO and NYISO. 

The purpose of long-term and short-term congestion products is to provide a hedge against real1 We use the term "Real-time Congestion Hedge" to represent the name of the product in the 

Day-Ahead market which is a spread between two specified locations. In PJM, that product is 

called the Up-To Congestion ("UTC") product. In ERCOT, it is called the Point-to-Point 

("P2P") product. In MISO, it is under development as the Virtual Spread Bid, and in NYISO it 

is under development as the Linked Virtual Transaction. Some also refer to the product as an 

Hourly Financial Transmission Right ("FTR"). 

{W6484564.2j 
134 


time congestion. This product brings value to any entity purchasing transmission and potentially 

being subject to real-time congestion, providing a means by which to mitigate real-time 

congestion exposure. In turn, financial market participants serve as counter-parties to such 

entities, injecting competition, risk mitigation and liquidity. 

To facilitate congestion hedging in a price sensitive manner, FERC and Congress should focus 

on the development of additional products, such as a Real-time congestion hedge, which would 

allow market participants to move congestion risk from the Real-time to the Day-ahead market 

when appropriate for managing risk. In addition to implementing longer-term FTRs, such as a 

ten year FTR auction, the addition of an hourly FTR, or Real-time congestion hedge, would 

allow market participants to hedge congestion in Real-time conditions. 

I attach hereto a white paper prepared by XO Energy, LLC advocating for the development of an 

Hourly FTR in all markets. That white paper demonstrates that the expansion of virtual products 

in all ISO/RTOs to include an Hourly FTR, or Real-Time Congestion Hedge, would cost less 

than $1 million per ISO/RTO to implement and would yield tens of millions of dollars per ISO 

annually in increased market efficiency. 

Stakeholder process. The primary issue that minority market participants, including financial 

market participants, face in the stakeholder process is the voting power of utilities. Entrenched 

utility interests have enormous strength in the stakeholder process because ISO/RTO rules 

employ weighted voting procedures, which distribute the number of votes based the number of 

subsidiaries within an organization. Further, stakeholders are broken into sectors with financial 

market participants grouped into large sectors, such as PJM's Other Supplier sector, where their 

votes are diluted by the sheer volume of organizations.2 As such, vertically integrated utilities 

are able to exert a large amount of influence on stakeholder proposals because the number of 

votes per organization, and the number of organizations per sector in sectors other than the Other 

Suppliers sector, vastly outweigh the voting power of smaller companies. ISOs/RTOs must be 

cognizant of the power and influence of utilities in the stakeholder process, in conjunction with 

each stakeholder's duty to vote with their company's financial interests in mind. Many smaller 

companies do not have the staff to dedicate to closely monitoring multiple ISO/RTO stakeholder 

proceedings, whereas larger entities utilize teams of individuals to drive the process. While the 

Financial Marketers Coalition has sought to bridge this gap through stakeholder representation, 

the process is still challenging. 

This combination can have the intended and unintended consequence of forcing proposals 

through the stakeholder process that may provide benefits for large utilities but are extremely 

adverse to market design. In a paper on electricity markets and virtual trading, two economists 

perfectly summed up the uplift debate in the PJM markets: 

The motivation for this paper arose from a vigorous policy debate about the 

merits of organized market designs in electricity markets. This debate reflects 

2 For example, there are 53 companies in PJM's Transmission Owners Sector, 40 companies in 

PJM's End User Customer Sector and 564 companies in PJM's Other Supplier Sector. This 

means one Transmission Owner's vote represents 0.025% of the sector, while one Other 

Supplier's vote represents 0.0018 %of the sector. 

2 
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two distinct, but related difficulties that frequently confront policy makers. First, 

the potential for a more efficient market design to reallocate production from 

high-cost firms to lower-cost competitors will create a political incentive for 

market participants that stand to lose to oppose it.3 

Weighted voting procedures allow utilities to set the course of stakeholder proceedings, which 

results in market reforms catered to utility interests with little regard for market outcomes, and as 

such, are often counter to consumers' best interests. P JM, for example, is required to implement 

market reforms arising from stakeholder proceedings, even if those reforms only benefit one 

sector, or are roundly opposed by one or two sectors. During the last Powering America hearing, 

Ranking Member Bobby Rush (D-IL) welcomed discussion on the market issues associated with 

ISO/RTOs beholden to incumbent utilities: 

As we will soon hear, Mr. Chairman, many consumer advocacy groups believe 

that the RTOs are too beholden to the utilities than they are trying to administrate. 

And consumers do not have a large enough seat at the table to make their voices 

heard. Many of these advocates argue that the whole process for reforming 

energy markets have become more and more complex, while at the same time 

consumer voices have been diluted to the point of being completely shut out. 

There also seems to be, a new consensus, Mr. Chairman, among today's 

witnesses, that PERC and DOE have become too tolerant of the RTOs' ability to 

shut out public interests, and participation, and policymakers must act to address 

this challenge.4 

Congress and PERC should support ISO!RTO reforms that prevent market participants, 

particularly entire sectors of market participants, from being effectively shut out of the 

stakeholder process. Particular attention should be given to increasing protections for minority 

interests, and a review of each ISO!RTO's rules pertaining to sector-weighted voting. 

In general, we question whether the stakeholder process should be the ultimate arbitrator of 

market design issues. It may not be in the best interests of consumers to have industry 

stakeholders holding the ability to change market design. The current practice places enormous 

pressure onto PERC as it must closely consider the actual impacts of a proposal, and not simply 

defer to the outcome of the stakeholder process. At the very least, best practices should guide 

market design issues, ideally aligning the ISO/RTO markets to some degree. After 20 years, we 

still have vastly different market structures across the United States. Interestingly, ERCOT, 

which is not regulated by PERC, has the most competitive market of all of the ISO!RTOs, even 

though it is the market which most recently moved from zonal to nodal pricing. Most 

3 Mansur, E. and White, M., Market Organization and Efficiency in Electricity Markets at 41 

(2012), available at http://www.dartmouth.edu/-mansur/papers/mansur white pjmaep.pdf 

(analyzing the benefits that PJM's expansion into the Midwest brought to regions previously not 

part of an organized market). 

4 Transcript of Powering America: Consumer-Oriented Perspectives on Improving the Nation's 

Electricity Markets at 3-4 (Oct. 7, 2017), available at http://docs.house.gov/meetingsf 

!Ff!F03/20171 005/1 06470/HHRG-115-IF03-Transcript-20 171 005.pdf 

{W6484564.2) 3 
136 


importantly, the end goal of electricity markets should not be a market design that benefits 

stakeholders, but a design which facilitates and encourages competition. 

Data and analysis. ISOs/RTOs, along with their market monitors, are currently able to provide 

data, analysis and conclusions to the public and to FERC without independent review from third 

parties. FERC relies on this data as a primary source of information to rule on proposed market 

reforms. In the past several years, ISOs/RTOs and their market monitors have questioned the 

value that financial marketers bring to the market, and have released data to FERC which can be 

construed as biased against financial market participants.5 In contrast, several economists and 

market experts have performed studies and analysis which reflect the exact opposite, that 

financial market participants and virtual products bring benefits to the market significantly in 

excess of the cost of their participation. Even independent market monitors' opinions on 

financial market participation vary wildly among ISOs/RTOs, further highlighting the disparity 

between data and opinion. In order to preserve neutrality, FERC and Congress should require 

that data, opinions and conclusions released by an ISO/RTO or its market monitor should 

undergo a peer review process by independent market experts. 

Uplift NOPR. In January 2017 FERC issued a Notice of Proposed Rulemaking on Uplift 

Allocation and Transparency in ISO/RTO markets. The Uplift NOPR is the culmination of years 

of work from FERC and market participants, including through FERC's price formation 

initiative, and if implemented, will significantly increase market efficiency, distribute market 

costs in an appropriate and equitable manner, and eliminate penalties that currently exist across 

many markets which disproportionately penalize efficient market behavior. Financial market 

participants strongly support the NOPR and believe that its reforms on uplift allocation and 

improved transparency in market operations and procedures will benefit all market participants. 

Now that FERC has a full quorum, it should focus on implementing this important rulemaking in 

all ISOs/RTOs as soon as possible. 

2) In your testimony, you stated that competitive markets should be allowed to operate 

with minimal government intervention, such as out-of-market subsidies. If such 

intervention occurs, how is financial trading affected? Do you have any recent 

examples? 

Answer: 

• Subsidies based on fuel source and out-of-market credits distort price formation, 

preventing markets from functioning efficiently 

• Congestion hedging products can produce cost savings by correctly identifying when 

transmission facility upgrades arc necessary for reliability 

When subsidies and other out-of-market credits are given to certain market participants or certain 

classes of market participants, those out-of-market actions distort market outcomes by decreasing 

the recipients' price responsiveness and price sensitivity. Out-of-market subsidies threaten 

competitive markets by suppressing prices, in both the capacity and electricity markets, sending 

5 At times, ISOs/RTOs, particularly PJM, have made significant market redesign proposals 

without any supporting data, or with only limited and questionable data. This is another issue to 

which FERC should be attuned. 

4 
137 


signals to investors that there is little or no opportunity to enter the market and receive 

sustainable economic rents. Existing resources which are not receiving subsidies will experience 

eroding profit margins, leading to those resources exiting the market or requesting cost-ofservice compensation. Subsidies threaten, and have the potential to irreversibly harm, 

competitive electricity markets and run counter to FERC's commitment to those markets. 

Subsidies Based on Fuel Type: Any subsidy which allows one particular class of market 

participant to compete with an advantage vis-a-vis other market participants will provide 

preferential treatment and skew market outcomes. When subsidies are given to a class of market 

participants based on the fuel source that participant is utilizing, the subsidy impacts the market 

clearing price and the individual LMPs throughout the grid. The subsidy payments lead to 

otherwise uneconomic generation remaining in the market or the early retirement of otherwise 

economic generation. This leads to price distortions in both the energy and capacity markets, 

which ultimately leads to increased costs to consumers. 

A recent report prepared by the Staff of the Department of Energy warned against the market 

distortions that could result from subsidies designed for limited types of resources. 6 The Staff 

Report cautioned that 

Interventions to promote specific fuel types-such as bailouts for coal and nuclear 

or mandates and subsidies for renewables-skew investment risk and can 

undermine incentives for reliability- enhancing behavior (e.g., a public 

intervention to finance pipeline expansion removes incentives for the private 

sector to invest in fuel security). Fuel-specific subsidies and mandates replace 

individual choice with collective choice. This one-size-fits-all approach to risk 

mitigation ignores variances in individuals' risk tolerances, results in high-cost 

risk mitigation, and creates perverse incentives for market participants by 

transferring risk and costs from the private to the public sector.7 

As DOE Staff acknowledges, subsidies based on fuel type have the potential to result in the 

retention of thousands of megawatts of uneconomic generation, ultimately crowding out efficient 

generation resources that are then forced to compete on a skewed playing field. This is 

dangerous for competitive markets because it forces resource owners to focus on gaining 

subsidies rather than maximizing the efficiency of their units. As Joseph Bowring, the 

independent market monitor for P JM has observed, "[ s ]ubsidies are contagious," and these types 

of programs will mean that "[c]ompetition in the markets could be replaced by competition to 

receive subsidies."8 

6 See Department of Energy, Staff Report to the Secretary on Electricity Markets and Reliability 

(Aug. 2017) ("DOE Staff Report"), https://energy.gov/downloads/download-staff-reportsecretary-electricity-markets-and-reliability. 

7 !d. at 90-91. 

8 Statement of Joseph Bowring at 3, State Policies and Wholesale Markets Operated by ISO New 

England, Inc., New York Independent System Operator, Inc., and PJM Interconnection, L.L.C., 

{W6484564.2} 5 
138 


Impact of Subsidies on Financial Trading: When placing transactions, financial participants are 

looking at the market signals that are sent from the ISO/RTO along with other factors. Taking a 

simplified example, if a generation unit's marginal cost to produce electricity is $30/MWh then 

we would expect that when the price is under that cost, the unit would either shut down or at the 

very least back down to minimum. Now assume that the same generator receives an out-ofmarket payment of $20/MWh. The impact of the out of market payment will result in the asset 

being able to produce electricity when prices are as low as $10/MWh, since the out-of-market 

payment will depress its marginal cost. This depression of wholesale prices will have a 

cascading impact across the footprint further distorting pricing and therefore distorting market 

outcomes. The electricity market does not recognize state borders. So the out of market actions 

of one state can have a drastic impact on the participants in another state. 

3) In theory, the benefits associated with financial transactions appear to make the 

markets more efficient. However, quantifying these benefits versus the costs is not easy 

because there are so many variables in the markets. What is your best argument to 

convince me that the value yon bring to the market is more than the value that you 

extract from it? 

Answer: 

• Noted economists have performed studies quantifying the benefits of financial 

transactions 

• To effectively quantify the benefit of financial transactions all analysis must include arerunning of the Real-time market 

Virtual trading brings specific benefits to wholesale markets, including convergence between the 

Day-ahead and Real-time markets, which helps to better preposition the Day-ahead market in 

preparation for the Real-time market. Convergence between the Day-ahead and Real-time 

markets is important because converged markets yield lower prices to consumers. By nature, 

energy markets are inherently volatile and risky because it can be hard for market participants to 

predict, in the Day-ahead market, what the Real-time market will look like. Financial market 

participants shoulder this risk on behalf of other market participants, allowing market 

participants to hedge the prices they will pay against the trades placed by a financial market 

participant. Financial marketers also bring needed liquidity and competition to markets, and 

introduce competition where otherwise none (or little) may exist. 

The benefits of virtual trading have been touted by premier market experts and ISO/RTO market 

monitors. Dr. William Hogan has written extensively on the issue, summarizing the benefits that 

virtual transactions bring to the market as follows: "This virtual bidding promotes price 

discovery, allows market-based redistribution of risk, and offers an opportunity to price risk in 

the electricity market."9 Similarly, Dr. David Patton, the market monitor for several ISOIRTOs, 

Docket No. AD 17-11-000 (filed Apr. 25, 20 17). See also DOE Staff Report at 14 (stating that 

economists have referred to the phrase "subsidies beget subsidies"). 

9 HOGAN, W., Electricity Market Design: Financial Transmission Rights, Up To Congestion 

Transactions and Multi-Settlement Systems (July 16, 2012) ("2012 Hogan Study"), available at 

http://www.hks.harvard.edu/fs/whogan/Hogan UTC 071612.pdf. 

{W6484S64.2) 6 
139 


has argued for increased virtual bidding in MISO, including recommending the development of 

the virtual spread bid or real-time congestion hedge product, 10 because of the value that such 

trading brings to the market: 

[A]ctive virtual trading in the day-ahead market promotes price convergence with 

the real-time market, which facilitates an efficient commitment of generating 

resources. In addition, active virtual supply protects the market against attempts 

to raise day-ahead prices by economically withholding physical generation or 

making excess load or virtual load purchases. 11 

In terms of quantifying benefits, Dr. Frank Wolak and Dr. Akshaya Jhu looked at the CAISO 

market, both before and after the introduction of Convergence Bidding. 12 The study found that 

savings specifically came in three areas. First, the annual total cost of fossil fuel energy 

decreased by about roughly $70 million dollars per year in the year following the introduction of 

Convergence Bidding, through more efficient unit commitment. Second, the study found, 

Convergence Bidding resulted in a reduction of greenhouse gas emissions of approximately 

2.8%, or between 537,000 and 650,000 pounds of emissions annually, again through better 

underlying unit commitment. 1 3 At the same time that year, the profits extracted from the market 

by entities trading Convergence Bidding was approximately $13 million in 2011 and $18 million 

in 2012. 14 While this study was done in the smaller CAISO market, it shows profound savingswith Convergence Bidding bringing value over four times greater than the cost of such trading 

in fuel costs alone, not including the value of avoided carbon emissions, and the longer term 

value of better pricing in the forward market to all market participants. 

Another economist has performed analysis which accounts for many different variables in the 

markets, and his conclusions found that the benefit of virtual transactions far outweighed the 

10 See, e.g., 2012 State of the Markets Report for the MISO Electricity Markets at 25 (June 

2013). 

11 2008 State of the Market Report for the Midwest ISO at 41. 

12 JHA, A AND WOLAK, F, Testing for Market Efficiency with Transaction Costs: An Application 

to Convergence Bidding in Wholesale Electricity Markets (May 7, 2013) (emphasis added), 

available at http://web.stanford.edu/group/fwolak/cgibin/sites/default/files/files/ 

CAISO_ VB_draft_ V8.pdf("Wolak Study"). 

13 This occurred through the pre-positioning of the Day-Ahead market, allowing more efficient 

units to run instead of the system operator calling on less-efficient units in the Real-Time market. 

Note that the dollar value of reduced greenhouse gas emissions is not included in the $70 million 

savings. 

14 California Independent System Operator, Market Issues and Peiformance: 2011 Annual 

Report at 87 (2011), http://www.caiso.com/Documents/2011Annua1Report-MarketlssuesPerformance.pdf; California Independent System Operator, Market Issues and Performance: 

2012 Annual Report at 109 (2012), http://www.caiso.com/Documents/2012Annua1ReportMarketlssue-Performance.pdf. We note that we refer only to the profits associated with internal 

Convergence Bidding, and do not include values associated with Convergence Bidding at the 

interties or in imports/exports. 

{W6484S64.2) 7 
140 


costs. Dr. Scott Holladay, an economist with Yes Energy, studied the impacts on convergence in 

the PJM market from a decrease in UTC volumes. He found that convergence in PJM was 

reduced by approximately $1.52/MWh from September 8, 2014 through November 6, 2014. 15 

Quantifying the benefits of virtual transactions is challenging. To accurately capture the 

numerous market variables impacting the analysis, it is essential that all post-analysis must 

include data re-running the Real-time market. However, the only entities which have sufficient 

information to either re-run the market or simulate a market re-run are the ISO/RTOs 

themselves, and FERC's Division of Analytics and Surveillance ("DAS"). Neither has been 

willing to share data with third party economists. As such, an independent study, performed by 

FERC or the Congressional Budget Office utilizing the ISO/RTO data provided to FERC's DAS, 

would be very helpful. 

The primary paper arguing against virtual transactions was published by Dr. John E. Parsons 

who, in conjunction with the FERC Office of Enforcement, performed an analysis of 

convergence bidding in the CAISO markets, questioning the value of virtual transactions and 

referencing certain virtual bidding as "purely parasitic."16 Dr. Parsons' paper was highly skewed 

against virtual trading, seeking to find examples to prove that such transactions are not beneficial 

to competitive wholesale electricity markets. Dr. Parsons' analysis focused on ramping events in 

CAISO where virtual traders were consistently buying Day-Ahead energy and profiting from the 

ramping and scarcity pricing that occurs during the peak hours in California when load is rising 

quickly and renewables are simultaneously ramping offline. One of the primary fatal flaws of 

Dr. Parson's analysis was in not re-running the Real-Time results. As such, Dr. Parsons failed to 

answer the critical question of whether the virtual transactions that were committing additional 

resources were lessening the frequency and severity of the shortage pricing events. He also 

failed to quantify how frequently his asserted "parasitic" results were occurring, which is highly 

relevant because "parasitic" results in 1% of hours would be far less of a concern than "parasitic" 

results in 35-50% of hours. Regardless, victuals were committing additional generation in the 

Day-ahead and making CAISO more reliable during scarcity events. 

4) In your testimony you mentioned that Financial Market Participants are the only 

stakeholders working to ensure that electricity markets provide useful price signaling 

for short-term and long-term decision making. 

Answer: 

• Financial market participants profit when their transactions help converge the Day-Ahead 

and Real-Time markets 

• Financial market participants help with prepositioning the Day-ahead market, risk 

mitigation and hedging, therefore reducing risk premiums which helps forward price 

formation. 

15 Speaker Materials of Holladay, S., Measures of Convergence In Up To Congestion Markets at 

8, Docket No. ELI4-37-000 (issued Jan. 7, 2015). 

16 Parsons, J .E., Financial Arbitrage and Efficient Dispatch in Wholesale Electricity Markets 

(Feb. 20 15), available at http://www.mit.edu/-jparsons/publications/20 150300 Financial 

Arbitrage and Efficient Dispatch.pdf 

{W6484S64.2} 8 
141 


• Long-term prices are derivative of short term prices. Financial participation helps get 

short-term prices right while reducing premiums. 

Financial market participants profit from activity that converges Day-ahead and Real-time prices 

and reduces out-of-market actions that produce uplift, an extraneous cost which ultimately 

increases prices for customers. By converging prices financial participants help improve the 

commitment and dispatch of assets, making the electric grid more efficient and reliable. 

Ultimately all market participants are seeking to perform profit-driven actions because all market 

participants are driven by individual financial obligations and fiduciary duties. 

Financial market participants are incentivized to produce efficient market outcomes because 

when they appropriately transact in a manner which brings Day-ahead and Real-time prices 

closer to one another, they profit. On the other hand, if they drive Day-ahead and Real-time 

prices further apart, they lose money. The market self-polices financial participants by 

rewarding those that enhance market efficiency and driving out of business those that don't. 

For example, a financial participant might forecast that the peak hour prices should be at least 

$50/MWh on a particularly constrained day. When the Day-ahead market clears at $40/MWh, 

the financial participant will have cleared their bid. In the Real-time market, if the financial 

participant forecasted correctly and the price comes in at $60/MWh, the financial participant will 

have earned a profit. On the other hand, if the financial participant offered $30/MWh on the 

same constrained day, that participant has contributed to lower-cost supply offers, causing the 

Day-ahead to clear at $35/MWh. Incorrect forecasting in the Day-ahead could prevent 

generation from being committed in the forward market, causing prices in Real-time to spike as 

high as $80/MWh. The financial participant would sustain a significant loss, and the market 

would be made less efficient and more volatile. 

The converse is true for other market participants who can derive profits from inefficiencies in 

the market, such as uplift payments for out-of-market dispatch. 

a. Will you explain bow financial market participants improve price signals and 

the effect that this bas on industry investment decisions? 

Financial market participants, and other types of market participants engaging in virtual 

transactions, send pricing signals through their activity. With virtual energy products such as 

INCs and DECs, they can send signals about where power may be priced too high in the Dayahead market, such that more generation may be needed. With FTRs and Real-time congestion 

hedging products such as the UTC, financial market participants send pricing signals about 

congestion in the Real-time: where it is likely to be found, how frequently it occurs and what 

pricing results from high congestion. As noted in the staff memo in advance of the hearing, 

congestion typically occurs if there is not enough capacity on a given transmission line, if the 

line is out of service for maintenance or if an unplanned outage occurs. Persistent congestion 

demonstrates a potential issue which may need to be addressed with some level of investment. 

In other words, these signals show where and when transmission upgrade investments may be 

necessary, by signaling when existing facilities are no longer able to accommodate the 

congestion in a particular area. Financial products are another tool in the toolbox for the regional 

transmission planning process. 

{W6484564.2} 9 
142 


WHOLESALE ELECTRICITY MARKET REFORM 

ENSURE THE AVAILABILITY OF A FINANCIAL DAY -AHEAD TRANSMISSION 

MARKET THAT WILL BE ALIGNED WITH THE EXISTING MONTHLY 

TRANSMISSION MARKET ACROSS ALL OF THE ISOS, RESULTING IN: 

• BILLIONS OF DOLLARS IN INCREASED EFFICIENCES; 

• IMPROVED GRID RELIABILITY; 

• FACILITATE COMPETITION ACROSS THE FERC-REGULATED 

ISOs; 

CONSUMER COST SAVINGS. 

January 2018 

I. A Call for the Modernization of the Electric Grid. 

Over the next two decades, it is anticipated that billions of dollars will be funneled into 

transmission and distribution investments in order to replace aging infrastructure and, in tum, enhance 

the resilience, reliability, safety and asset security of the electric grid. This is the primary focus of the 

Quadrennial Energy Review (QER): Energy Transmission, Storage, and Distribution Infrastructure, 

April2015. 

II. Deregulation Facilitates the Creation of Energy and Transmission Products. 

Nearly twenty years ago, FERC commenced the deregulation of the wholesale electricity 

markets, allowing the unbundling of energy transactions. Unlocking access to the transmission system, 

while promoting competition, exposed market design challenges that required the creation of both a 

framework and operational capability to transact between generation and load. 

Prior to deregulation, vertically integrated utilities owned generation and entered into long-term, 

price-inflated agreements on behalf of the load that they served. The competitive model required the 

replacement of the vertically integrated system with an efficient market design whereby generated 

energy and transmission could be independently transacted. 

III. Energy and Transmission Products in the Forward Markets. 

The right to acquire energy and transmission can be transacted years or months in advance. The 

acquisition of energy and transmission in the forward markets ensures that generated resources together 

with the right to transmit those resources from generation to load will be available years or months before 

they are needed to meet grid demand, safeguarding grid reliability and creating long-term price signals. 

In the real-time market, the price of both energy and transmission can be far more volatile than 

expected in the forward markets. To address this volatility, economists recognized that the creation of 
143 


a day-ahead market would facilitate a more economic dispatch of electricity in real time. By prepositioning market operations on a day-ahead basis (versus months or years in advance), real-time 

generation and load could be more accurately predicted, resulting in greater price certainty and 

stabilization. 

Since the introduction of the day-ahead market model in each of the ISOs, energy has been 

available for trading on a day-ahead basis. In addition to acquiring energy months or years in advance, 

trading in the day-ahead market offers increased granularity - the ability to assess and hedge against 

energy market price fluctuations in discrete periodic increments closer to real-time (e.g., on an hourly 

basis one day in advance). 

Within PJM, the first ISO that was established, it was recognized that energy and transmission 

were fundamentally intertwined. In order to serve load in a price sensitive manner, the cost of 

transmission had to be considered as well. This recognition resulted in the expansion of PJM's dayahead market to include the transacting of not just energy rights, but transmission rights, in order to 

better address the price volatility that occurred within PJM's footprint. Significantly, PJM's day-ahead 

transmission rights are only available in 3% of the market and have not been geographically expanded 

since their introduction. 

Unfortunately, the ability to transact transmission on a day-ahead basis was not uniformly 

implemented by the other PERC-regulated lSOs. ERCOT, which is not under FERC jurisdiction, 

implemented a day-ahead market for both energy and transmission that is available across ERCOT's 

entire footprint. It is critical that these day-ahead transmission rights are available to the fullest extent 

across all ISOs in order to lead to more accurate price formation and market efficiency. 

IV. The Changing Landscape of the Grid Requires the Expansion of the Day-Ahead Markets 

in all ISOs to include Transmission. 

The modernization of the grid has been made all the more urgent by our pervasive dependence 

on a reliable supply of electricity. The principal challenges facing the grid: (i) revitalizing the aging 

infrastructure, which will require billions if not trillions of dollars in capital investments, and (ii) 

integrating variable energy sources, while maintaining stability in supply and price. 

The sources of energy generation on the grid have changed dramatically. According to the U.S. 

Energy Information Administration, variable energy systems, including solar, wind, and hydropower, 

generated an unprecedented 523 million megawatt-hours of electricity in the United States in 2013, with 

variable generation on the rise. Furthermore, the retirement of coal-fired generators and, to a lesser 

extent, nuclear power plants, has precipitated our reliance on natural gas-fueled generators for a source 

of fully-dispatchable supply. 

With the changing landscape of the grid, it is imperative that the day-ahead markets of all ISOs 

are expanded to include transmission. The transformation of the U.S. energy generation portfolio, while 

providing other potential benefits, will trigger a resurgence of price volatility if market participants are 

unable to hedge against price fluctuations in both energy and transmission in a more granular manner 

that is, in the day-ahead market. 

In order to improve market design efficiencies as well as effectively respond to a more dynamic 

generation portfolio, it is critical that the day-ahead market accommodate the transaction of both energy 

and transmission. Ensuring the availability of a financial day-ahead transmission market that is aligned 

with the existing financial monthly transmission market will improve market efficiency, reliability and 

2 
144 


price certainty by more effectively pre-positioning the markets on a day-ahead basis to support the 

economic dispatch of electricity in real-time. 

V. Recommended Action. 

Billions of dollars will be invested into the modernization of the electric grid, which will take 

decades to complete. In the near term, ensuring the availability of a financial day-ahead transmission 

market that is aligned with the existing financial monthly transmission market across all of the ISOs will 

facilitate market efficiency, reliability and the integration of a more diverse generation portfolio. 

It is estimated that the implementation of a financial day-ahead transmission market, which can 

be included in the budgets of each of five lSOs for $500,000- $1 million, respectively, with an estimated 

launch period of less than one year, will conservatively result in tens of millions of dollars per 

annum/ISO in increased market efficiencies. 

* * * * * 

Accordingly, FERC should encourage the lSOs to implement a fully-functional, financial dayahead transmission market that will be aligned with the existing financial monthly transmission 

market. The implementation of a financial day-ahead transmission market will encourage more accurate 

price formation, which will improve market efficiency and performance, foster reliability, lower 

electricity prices, and facilitate the integration of variable renewable energy sources. 

Senate and House provisions that were pending in the 2016 energy bill conference offered an 

opportunity to move forward on a day-ahead market for transmission, however, we understand that the 

proposed bill was subsequently abandoned. We strongly support the implementation of a more intensive 

and comprehensive bill. 

3 
145 


GREG WALDEN, OREGON 

CHAIRMAN 

Dr. Eric Hildebrandt 

ONE HUNDRED FIFTEENTH CONGRESS 

FRANK PALLONE, JR., NEW JERSEY 

RANKING MEMBER 

C!Congre~~ of tbc Wnitcb ~tate~ 

~ou£le of i\cpre£lentatibc£l 

COMMITTEE ON ENERGY AND COMMERCE 

2125 RAYBURN HousE OFFICE BuiLDING 

WASHINGTON, DC 20515-6115 (202)225-2927 

(202}225-3£41 

December 19,2017 

Director of Market Monitoring 

California ISO 

250 Outcropping Way 

Folsom, CA 95630 

Dear Dr. Hildebrandt: 

Thank you for appearing before the Subcommittee on Energy on November 29,2017, to testify 

at the hearing entitled "Powering America: Examining the Role of Financial Trading in the Electricity 

Markets," 

Pursuant to the Rules of the Committee on Energy and Commerce, the hearing record remains 

open for ten business days to permit Members to submit additional questions for the record, which are 

attached. The format of your responses to these questions should be as follows: (1) the name of the 

Member whose question you are addressing, (2) the complete text of the question you are addressing in 

bold, and (3) your answer to that question in plain text. 

To facilitate the printing of the hearing record, please respond to these questions with a 

transmittal letter by the close of business on Tuesday, January 9, 20!7. Your responses should be mailed 

to Allie Bury, Legislative Clerk, Committee on Energy and Commerce, 2125 Rayburn House Office 

Building, Washington, DC 20515 and e-mailed in Word format to Allie.Burv@mail.house.gov. 

Thank you again for your time and effort preparing and delivering testimony before the 

Subcommittee. 

Sincerely, 

cc: The Honorable Bobby L. Rush, Ranking Member, Subcommittee on Energy 

Attachment 
146 


January 9, 2018 

Ms. Allie Bury 

Legislative Clerk 

Committee on Energy and Commerce 

2125 Rayburn House Office Building 

Washington, D.C. 20515 

Allie.Burv@majl.house.gov 

Dear Ms. Bury: 

California Independent System Operator Corpo1at!on 

I appreciated the opportunity to appear before the Subcommittee on Energy on November 

29, 2017 to testify at the hearing entitled 'Powering America: Examining the Role of Rnancial 

Trading in the Electricity Markets.' 

Attached are responses to the additional questions provided in writing by the Honorable 

Fred Upton via letter dated December 19,2017. 

Sincerely, 

Eric Hildebrandt, Ph.D. 

Director of Market Monitoring 

nAinArtm••ntof Market Monitoring 

Operator 

Attachment 

www.calso.com I 250 Outcropping Way, Folsom, CA 95630 I 916.351.4400 
147 


Response to Additional Questions for the Record 

Eric Hildebrandt, Ph.D. 

Director, Department of Market Monitoring 

California Independent System Operator Corporation 

Committee on Energy and Commerce 

Subcommittee on Energy 

United States House of Representatives 

January 9, 2018 

The Honorable Fred Upton 

1. In your testimony, you state that market design flaws associated with 

Financial Transmission Rights (FTRs) is costing ratepayers over $400 million 

a year. Why does every RTO and ISO have this flaw and what is your 

proposed solution? 

A review of congressional legislation and related proposals and decisions by the 

Federal Energy Regulatory Commission (FERC) clearly shows that FTRs were created 

for the express purpose of benefiting customers by allowing load serving entities (LSEs) 

to hedge power purchases made by LSEs on behalf of their customers. All ISOs/RTOs 

do this by allocating FTRs directly to load serving entities (LSEs).1 Moreover, prior 

proposed rules and orders by FERC clearly indicate that auctions for FTRs were initially 

developed and envisioned only as a means for providing a secondary market in which 

LSEs could choose to sell any FTRs they were allocated if they felt this was economic 

to do so. However, all ISOs/RTOs have gone beyond the initial intent and requirements 

for FTRs established by Congress and the FERC by establishing auctions in which 

1 Some ISOs!RTOs allocate LSEs auction revenue rights (ARRs), which can be directly converted into 

FTRs and are essentially equivalent to FTRs. 

1 
148 


180/RTOs auction off additional FTRs backed by congestion revenues that would 

otherwise be refunded to transmission ratepayers. 

The Commission addressed FTRs in 2002 as part of its initial Standard Market 

Design (SMD) proposal, which stated: 

To provide the price signals needed to manage congestion, the Independent 

Transmission Provider will be required to operate a day-ahead and real-time market 

for energy. To provide customers with a mechanism for achieving price certainty 

under the new congestion management system, we also propose to require that 

customers be given Congestion Revenue Rights for their historical uses that protect 

against congestion costs when specific receipt and delivery points are used. 2 

FERC's initial SMD proposal included a requirement for ISOs/RTOs "to offer 

Congestion Revenue Rights for all of the transmission transfer capability on the grid," 3 

and included a "preference for the auction of Congestion Revenue Rights," but would 

have allowed "regional flexibility for a four-year transition period in determining whether 

to allocate Congestion Revenue Rights to existing customers or auction rights such that 

revenues are allocated to existing customers to hold them financially harmless [to the 

financial consequences of congestion in markets based on locational marginal pricing]. 4 

FERC's initial 2002 proposal also indicated that the Commission believed it is important 

that ISOs/RTOs facilitate an active secondary market for CRRs by holding an auction in 

which "buyers and sellers would submit bids that specify the type of Congestion 

Revenue Rights desired to be bought or sold .. " 5 

2 Remedying Undue Discrimination, Through Open Access Transmission Service and Standard 

Electricity Market Design, July 21, 20012, Notice of Proposed Rulemaking, Docket No. RM01-12-000, 

(2002 Standard Market Design Proposal) '11111. 

3 2002 Standard Market Design Proposal, '11237 

4 2002 Standard Market Design Proposal, '1115 

5 2002 Standard Market Design Proposal, '1!252 

2 
149 


In 2003 FERC issued a Standard Market Design White Paper in response to 

comments and concerns submitted on its initial SMD NOPR. This paper again indicated 

that "RTOs and ISOs that use locational pricing to manage congestion would be 

required to make Firm Transmission Rights (FTRs) available to customers .... [to] 

protect customers from the costs of congestion",6 but went on to clarify that ISOs would 

not be required to auction FTRs: 

The Final Rule will eliminate any requirement that FTRs be auctioned. We will, 

instead, look to regional state committees to determine how such rights should be 

allocated to current customers based on current uses of the grid. Varying 

approaches to FTR allocation need not create "seams" with neighboring regions. 7 

FERC's 2003 whitepaper also clarified that rather than requiring ISOs to auction 

off additional FTRs, ISOs would be required to operate a secondary market for the 

purpose of allowing load serving entities that were allocated FTRs to voluntarily sell 

their FTRs if they so choose~ 

There would be no requirement to auction these FTRs either initially or after a 

transition period ..... Once the initial allocation of FTRs is completed, the RTO or 

ISO must operate a secondary market for holders of FTRs to voluntarily sell their 

FTRs to others. a 

Although FERC's standard market design rulemaking proposal was terminated 

and never adopted, the Energy Policy Act of 2005 added a new section to the Federal 

Power Act which again clarified that requirements placed on ISOs/RTOs relating to 

FTRs were intended to pertain only to the service obligations and power contracting 

needs of load serving entities'- and were not required for the benefit of financial traders 

or hedging by power producers: 

6 White Paper on Wholesale Power Market Platform, April 28, 2003, p.10. 

7 White Paper on Wholesale Power Market Platform, p.5 

8 White Paper on Wholesale Power Market Platform, Appendix A. p.9 

3 
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The Commission shall exercise the authority of the Commission under this Act in a 

manner that facilitates the planning and expansion of transmission facilities to meet 

the reasonable needs of load-serving entities to satisfy the service obligations of the 

load-serving entities, and enables load-serving entities to secure firm transmission 

rights (or equivalent tradable or financial rights) on a long-term basis for long-term 

power supply arrangements made, or planned, to meet such needs. 9 

In Order 681 the Commission clarified once again that FTRs were intended to 

provide a way for load serving entities who purchase electricity (rather than entities that 

sell electricity) to hedge congestion costs. 

The primary objective of guideline (1), consistent with section 217(b)(4), is to allow a 

load serving entity to obtain a long-term firm transmission right for purposes of 

hedging congestion charges associated with delivery of power from a long-term 

power supply arrangement to its load. We will adopt guideline (1) without 

modification. 10 

Order 681 also made it abundantly clear that requirements relating to FTRs 

established through the Energy Policy Act of 2005 applied only to the allocation of FTRs 

to load serving entities- and does not require the sales of additional FTRs by an ISO 

through an auction. 11 

As illustrated above, all requirements in Federal legislation and related to FERC 

decisions concerning FTRs are designed to provide hedges to load serving entities who 

purchase energy. These requirements were not established to meet the desires of 

financial entities or generation owners. Thus, even if some FTRs are used by 

generation owners as hedges for sales of power, it is unjust and unreasonable to ask 

customers of load serving entities who pay for the cost of the nation's transmission 

system to continue to lose $400 million to $600 million per year to subsidize any such 

9 Pub. L. No. 109-58, § 1233, 119 Stat. 594,958 

10 Order No. 681, Final Rule, July 20, 2006, 1!116 at p. 66. 

11 e.g. see Order No. 681, Final Rule, July 20, 2006, 1!361 to 1f393 at pp.172-190. 

4 
151 


hedges. Moreover, analysis shows that the bulk of FTRs purchased in auction are 

purchased by financial entities rather than by generation owners that might use these as 

hedges. 

ISOs/RTOs do not need to auction FTRs for generation owners or energy traders 

to gain access to physical transmission or to hedge price risks associated with 

wholesale energy contracts and trading. As with other commodities, market 

participants and financial entities are free to develop and trade price swap contracts. In 

fact, this type of free market- with trades between willing buyers and sellers - is what is 

needed to price such price swaps most efficiently and fairly. If policy makers believe it is 

beneficial to wholesale electricity markets and consumers for !SO's to facilitate such 

financial price swaps, then I SO's should do this through a market for FTRs that is 

cleared and settled based on bids and offers from willing buyers and sellers. 

In financial terms, all FTR auctions involve the sale of financial hedging contracts 

that are backed by transmission ratepayers which are auctioned off by ISOs/RTOs at a 

$0 offer price. This market design essentially forces transmission ratepayers to sell 

these financial contracts as "price takers" in the auction. This basic market design flaw 

can only be completely and effectively addressed by replacing these auctions with a 

market for financial hedging contracts that is based entirely on bids submitted by willing 

buyers and sellers. 

A report posted on our website provides a discussion of market-based options 

through which energy generators, traders and financial entities can buy and sell 

financial instruments that allow hedging of congestion costs - without requiring the 

nation's transmission ratepayers to incur the enormous financial losses they are 

5 
152 


incurring as a result of FTR auctions currently operated by the nation's largest 

ISO's/RTOs. 12 

The Honorable Fred Upton 

2. I understand that sometimes the revenue paid out to Financial Transmission 

Right (FTR) holders is greater than the revenue generated by FTRs, resulting 

in a revenue shortfall. When this occurs, where does the money come from 

to cover the shortfall? 

In the nation's largest ISO/RTOs, the revenue paid out to entities that purchase 

FTRs in auction is consistently and systematically greater than the revenue generated 

by the sale of FTRs in these auctions. FTRs are paid out of congestion revenues 

collected by the ISOs/RTOs. Any congestion revenues not paid out to FTR holders are 

refunded to LSEs. Therefore, the difference between auction revenues and congestion 

revenue paid out to FTRs purchased in the auction represents a direct loss to load 

serving entities. While the LSEs get the auction revenue, they consistently give up 

much more in congestion revenue in return. 

In her testimony on behalf of the Power Trading Institute, Ms. Noha Sid hom 

notes that a "good analogy" of transmission congestion charges is the higher tolls 

collected for use of a highway during rush hour.13 Using this analogy, FTR auctions are 

analogous to a state government auctioning off the rights to the tolls collected on public 

12 Market alternatives to the congestion revenue rights auction, Department of Market Monitoring, 

California Independent System Operator, November 27, 2017. 

http://www.caiso.com/Documents/Market Atternatives CongestionRevenueRightsAuctionNov27 2017 .pdf 

13 Noha Sidhom, CEO of TPC Energy, LLC on behalf of the Power Trading Institute Subcommittee on 

Energy Committee on Energy and Commerce U.S. House of Representatives Hearing: Examining the 

Role of Financial Trading in the Electricity Markets November 29, 2017, p.2. 

http://docs. house.gov/meetings/IF/IF03/20171129/1 06663/HHRG-115-IF03-Wstate-SidhomN20171129.pdf 

6 
153 


highways by the state for a future time period to the highest bidder. However, in this 

analogy, the revenues received by the state from this auction are consistently far below 

the tolls collected by the state. Thus, without such an auction, the toll revenues 

collected by the government would offset a much greater part of the cost to the state's 

taxpayers who paid the full cost of building the highway. 

In response to the question of where the money to pay FTRs comes from, Ms. 

Sid hom also stated that "the value of allocated rights [to LSEs] is determined in the FTR 

auction," and that FTR auctions save money for consumers since "they provide an 

accurate price for the contracts that are allocated to transmission customers 

representing consumers." 14 This is simply not the case in any ISO/RTO. FERC 

originally envisioned that ISOs could conduct FTR auctions as one way for LSEs to 

voluntarily sell any allocated FTRs if they felt this was economically advantageous for 

them to do so. However, there is no link whatsoever between the economic value 

received by LSEs from allocated FTRs that they retain and the price of the additional 

FTRs sold by an ISO in an auction. On the contrary, LSEs retain their allocated FTRs 

and receive FTR payments that are much greater than the price of FTRs sold in the 

auction. 

Ms. Sid hom also contends that "basically, this is a public auction of excess 

capacity."15 Again, this is simply not the case. As Ms. Sidhom acknowledged, FTRs 

are purely financial price swap contracts, and provide no physical access or rights to the 

transmission grid. Congestion revenues are only generated when congestion occurs on 

1• Noha Sidhom, p.7-8 

1s Noha Sidhom, p.7. 

7 
154 


the transmission system when there is not excess capacity. And if additional FTRs 

were not auctioned off by the ISO, all of these congestion revenues would be allocated 

back to LSEs which pay for the full cost of the transmission system through the 

Transmission Access Charge (T A C). 

In the CAISO, the financial impact of FTRs auctioned off by ISOs on transmission 

ratepayers occurs through the Congestion Revenue Rights balancing account.16 Table 

1 below shows totals for this settlement account for 2017. As shown in Table 1, total 

congestion revenues in the CAISO totaled $357 million in 2017. A net total of about 

$279 million in CRR payments were made to LSEs receiving CRRs through the 

allocation processY The CAISO's CRR auction generated about $83 million in 

revenues from non-LSEs, but resulted in CRR payments of about $184 million to these 

non-LSEs- resulting in a loss of about $100 million to LSE's. 

Table 1. CAISO Congestion Revenue Rights Account, 2017 

(Millions of dollars) 

Day-ahead market congestion rent 

Net CRR payments to LSEs* 

Net CRR auction revenues from non-LSEs 

Net payments to non-LSE auction CRRs 

Account surplus/deficit 

With CRR 

auction 

$357 

($279) 

$83 

($184) 

($22.6) 

Without 

CRR 

auction 

$357 

($279) 

$78 

As shown in Table 1, this resulted in a deficit in the CRR balancing account of 

about $22 million, which is charged to LSEs based on their pro rata share of load and 

16 As noted in my November 29 testimony, FTRs are called Congestion Revenue Rights (CRRs) in the 

CAISO. 

17 This net total includes payments to allocated CRRs, net payments to LSE auction CRRs, and net 

auction revenues paid by LSEs 

8 
155 


exports. However, if no additional CRRs were auctioned off by the CAISO, a total of 

$78 million would be credited back to LSEs. Thus, as a result of the auction, LSEs 

received an additional charge of $22 million rather than receiving a credit back of $78 

million. This represents a loss of about $100 million to LSEs in the CAISO in 2017 as a 

result of additional FTRs auctioned off by the CAISO. 

2a. How often does this occur and on what scale? 

The $400 million per year cited in my testimony represents our estimate of the 

lower end of the costs being imposed on the nation's electric transmission ratepayers 

through FTR auctions. Analysis from Stanford University's Economics Department 

places this figure at $600 million per year. 18 These analyses show that ratepayer losses 

from sales of FTRs by ISOs represent a very systematic and consistent long term trend, 

and have now occurred each year for over almost a decade. 

In the CAISO, transmission ratepayers have lost money on FTRs sold in the 

CAISO's auction every year since the auction began in 2009. Losses have totaled over 

$756 million or an average of $80 million per year. 19 In 2017 losses to transmission 

ratepayers from FTRs sold at auction totaled over $100 million. Similar results have 

been consistently reported based on data from the nation's other three largest ISOs and 

RTOs: 

18 paper 

19 These data have been updated since my November 29 testimony to include results through the end of 

2017. 

9 
156 


• Research from the Stanford University Economics Department shows that in the 

New York ISO ratepayer losses were $938 million from 1999 to 2016, or almost 

$60 million per year.zo 

• In PJM, ratepayers have lost over $1.18 billion from 2011 through September 

2017 according to PJM's Independent Market Monitor. Financial entities have 

received about $170 million per year in FTR profits. 21 

• In the Midcontinent ISO (MISO) for the 2010-2011 through 2016-2017 planning 

periods, on average only about 80 percent of the day-ahead market congestion 

rent was received by transmission ratepayers. 22 As explained in earlier DMM 

reports, this implies that transmission ratepayer losses in the FTR auction were 

equal to about 20 percent of day-ahead congestion rents for the period.23 Dayahead congestion rent averaged about $790 million from 2011 through 2016. 24 

2o Leslie, Gordon "Why do transmission congestion contract auctions cost ratepayers money? Evidence 

from New York" November 14, 2017, downloaded 11/17/2017: 

http://www.web.stanford.edu/-gwleslie/index new files/Leslie JMP20171114.pdf 

21 Monitoring Analytics, 2016 State of the Market Report forPJMp. 553: 

http://www.monitoringanalvtics.com/reports/PJM State of the Market/2016/2016-som-pjm-sec13.pdf 

Monitoring Analytics, 2017 Quarterly State of the Market Report for PJM: January through December p. 

559: http://www.monitoringanalytics.com/reports/PJM State of the Market/2016f2016-som-pjmsec13.pdf 

22 Midcontinent ISO ARRIFTR Transmission Customer Metric May 11, 2017: 

https:/lwww.misoenergy.org/librarv/Repositorv/Meetinq%20Materiai/Stakeholder/MSC/2017/20170511/ 

20170511 %20MSC%201tem%20XX%20ARR%20FTR%20Transmission%20Customer%20Metric%20A 

prii%202017%20Update.pdf 

23 Department of Market Monitoring Shortcomings in the Congestion Revenue Right Auction Design p.6: 

https://www.caiso.com/Documents/DMM-WhitePaper-ShortcomingsCongestionRevenueRightAuctionDesign.pdf 

24 MISO day-ahead congestion rent data from Potomac Economics 2016 State of the Market Report for 

the MISO Electricity Market p.50; Potomac Economics 2014 State of the Market Report for the MISO 

Electricity Market p. 52; Potomac Economics 2012 State of the Market Report for the MISO Electricity 

Market p.46. Reports available at: 

https://www.misoenergy.org/MARKETSOPERATIONS/INDEPENDENTMARKETMONITOR/Paqes/lnde 

pendentMarketMonitor.aspx 

10 
157 


This data indicates that transmission ratepayers in MISO have consistently 

suffered large losses from the FTR auctions, between $100 million and $200 

million per year. 

The Honorable Fred Upton 

3. You testified that financial instruments are essentially price swap contracts 

and that unlike such contracts for other commodities, FTRs sold in electricity 

markets are not cleared and seWed based on bids from willing buyers and 

sellers, but instead auctioned off by market operators. Can you explain in 

further detail why this is the case? 

As explained in response to Question 1, a review of congressional legislation and 

related proposals and decisions by the FERC shows that FTRs were originally meant to 

provide a way for LSEs to hedge their electricity purchases. This can be accomplished 

by allocation of FTRs to LSEs and does not require an auction of additional FTRs by the 

ISO. 

We do not know exactly why all ISOs and RTOs adopted FTR auctions. Dr. 

William W. Hogan developed the theory of using FTRs (which he originally called 

network contracts) to allocate congestion rents in 1992. 25 In this paper, Dr. Hogan 

expresses the belief that FTRs define rights that are amenable to market trading. Dr. 

Hogan writes that " ... the contract network framework can support the allocation of 

transmission capacity rights through a competitive bidding system." Dr. Hogan's paper 

also seems to assume the auction would be competitive with prices equaling the 

expected spot market congestion prices. 26 The policy that subsequently established 

25 Hogan, William W. Contract Networks for Electric Power Transmission: Technical Reference, 1992, 

https://sites.hks.harvard.edu/fs/whogan/acnetref.pdf 

26 Hogan, pp.38 and 42. 

11 
158 


FTR auctions appears to have been influenced by this narrative initiated by Dr. Hogan 

- if the ISO can get the FTR transmission model exactly right and if the auction market 

is competitive, then auction revenues should equal the expected payouts. 

However, the literature and policy proceedings on FTRs reflect very little 

recognition of the fact that the auction obligates transmission ratepayers to sell financial 

swaps regardless of the sale price. Similarly, the risk that this creates for ratepayers to 

suffer large losses from FTR auctions does not appear to have been widely recognized. 

In the MISO and NYISO, neither the ISO nor its market monitor have reported the 

information necessary to directly quantify these losses. But the financial risk and 

obligations placed on ratepayers by FTR auctions and the discrepancy between FTR 

auction prices and payments is now very evident. 

One factor underlying the flawed nature of auctioning FTRs backed by 

transmission ratepayers is the complexity of FTRs as a financial product. As explained 

in a 2014 expose on FTRs in the New York Times: 

Across the nation, investment funds and major banks are wagering billions on 

[transmission congestion contracts], as they chase profits in an arcane arena that 

rarely attracts attention ... The utilities and power companies suggest they cannot win 

against trading outfits that employ math specialists, often called ·quants,' to spot 

lucrative opportunities. With transmission contracts, there are tens of thousands of 

tradable combinations." 

As explained in academic research from Stanford University, the complexity of 

FTRs as a product creates a major barrier to entry and competition in the FTR auction: 

Anecdotes suggest a major barrier to eroding total trading profits could be the cost 

for new entrants to develop a technology that can identify successful trading 

strategies in these auctions. The auctions are notoriously complex, where TCC 

27 "Traders Profit as Power Grid is Overworked" The New York Times August 14, 2014: 

https://www. nvtimes.com/2014/08/15/business/energy-environmenVtraders-profit-as-power -grid-isoverworked.html 

12 
159 


payouts and the auction allocations are determined in part by physical transmission 

constraints in the electric network. Successful firms consistently update their models 

and aggressively enforce non-disclosure agreements with ex-employees. The 

persistence of total trading profits over 16 years and the protection firms place on 

their trading technologies suggest that if regulators wish to reduce the transfers of 

wealth from electricity customers to TCC holders, waiting for future trader entry may 

not achieve this goal. Policy modifications may be required ... such as eliminating 

the markets or restricting the set of products offered. 28 

This research also makes the important point that the large number of potential 

products and product combinations in the FTR auction can dissipate effective market 

liquidity. 

A detailed discussion of the fundamental economic flaws underlying the 

auctioning of FTRs are provided in a recent report by the California I SO's Department of 

Market Monitoring.29 This report identifies a variety of factors that are likely to help 

explain the very poor performance of the CRR auction from the perspective of 

ratepayers. These include: 

• FTRs are not consistently defined products in both the auction and day-ahead 

market. A substantial body of economic literature exists that explains how this 

condition leads to underpricing in auctions for a variety of commodities.30 

28Leslie, Gordon "Why do transmission congestion contract auctions cost ratepayers money? Evidence 

from New York" November 14, 2017, p. 4. 

http://www.web.stanford.edu/-gwleslie/index new files/Leslie JMP20171114.pdf 

29 Problems in the performance and design of the congestion revenue right auction, Department of Market 

Monitoring, California Independent System Operator, November 27, 2017. 

http://www.caiso.com/Documents/DMMWhitePaperProblems Performance Design CongestionRevenueRightAuction-Nov27 2017.pdf 

3

° For example, see: Athey, Susan, and Jonathan Levin. 2001. "Information and competition in US Forest 

timber auctions." Journal of Political Economy, p. 377 at 

http://web.stanford.edu/-jdlevin/Papers/Skewing.pdf; and Agarwal, Nikhil, Susan Athey, and David 

Yang. 2009. "Skewed Bidding in Pay Per Action Auctions for Online Advertising" The American 

Economic Review at h!tp://economics.mit.edu/files/10630. 

13 
160 


• FTR auction participants can profit from better information on differences in the 

way CRRs are defined in the auction versus the day-ahead market- without 

increasing efficiency or adding any value to ratepayers or other market 

participants. 

• LSEs representing transmission ratepayers face significant limitations to bidding 

in FTR auctions. 

• Buyers do not have an incentive to bid auctioned FTRs up to their expected 

value. 

These represent fundamental flaws that cannot be eliminated under the current 

FTR market design. These flaws cannot be removed or fixed by simply improving the 

accuracy of the transmission network model used in the FTR auction, as some suggest. 

These flaws can only be entirely and effectively addressed by replacing the current 

auction design with either a bilateral market or centralized market for price swaps or a 

voluntary market for price swaps between willing buyers and sellers. However, the 

option of a centrally run market administered by ISOs/RTOs should only be pursued if 

policymakers believe that the benefits of facilitating price swaps warrant or require 

intervention by the ISOs/RTOs, rather than allowing price swaps to occur through 

private mechanisms as occurs with other commodities. 

14 
161 


GREG WALDEN, OREGON 

CHAIRMAN 

Mr. Max Minzner 

Partner 

Jenner & Block LLP 

ONE HUNDRED FIFTEENTH CONGRESS 

FRANK PALLONE, JR., NEW JERSEY 

RANKING MEMBER 

C!Congre~~ of tbe Wntteb $tate~ 

j!Jouse of l\epresentattbes 

COMMITTEE ON ENERGY AND COMMERCE 

2125 RAYBURN HousE OFFICE BuiLDING 

WASHINGTON, DC 20515-£115 (7.02) 225-2927 

(202)225-3641 

December 19,2017 

1099 New York Avenue, N.W.; Suite 900 

Washington, DC 20001 

Dear Mr. Minzner: 

Thank you for appearing before the Subcommittee on Energy on November 29,2017, to testify 

at the hearing entitled "Powering America: Examining the Role of Financial Trading in the Electricity 

Markets." 

Pursuant to the Rules of the Committee on Energy and Commerce, the hearing record remains 

open for ten business days to penn it Members to submit additional questions for the record, which are 

attached. The format of your responses to these questions should be as follows: (1) the name of the 

Member whose question you are addressing, (2) the complete text of the question you are addressing in 

bold, and (3) your answer to that question in plain text. 

To facilitate the printing of the hearing record, please respond to these questions with a 

transmittal letter by the close of business on Tuesday, January 9, 2017. Your responses should be mailed 

to Allie Bury, Legislative Clerk, Committee on Energy and Commerce, 2125 Rayburn House Office 

Building, Washington, DC 20515 and e-mailed in Word format to Allie.flurv(ihnail.house.gov. 

Thank you again for your time and effort preparing and delivering testimony before the 

Subcommittee. 

Sincerely, 

cc: The Honorable Bobby L, Rush, Ranking Member, Subcommittee on Energy 

Attachment 
162 


1099 N£W YORK AVENUE, NW SUIT£ 900 WASHINGTON, DC 20001·44t:z 

January 8, 2018 

The Honorable Fred Upton, Chairman 

Subcommittee on Energy 

House of Representatives 

Committee on Energy and Commerce 

2125 Rayburn House Office Building 

Washington, D.C. 205 l 5 

Dear Chairman Upton: 

.J E N N E R &. B L 0 c K LLP 

MaxMinzner 

Thank you for your December 19, 2017 letter containing additional questions for the hearing record on "Powering 

America: Examining the Role of Financial Trading in the Electricity Markets." 

My responses to the questions are enclosed. I want to thank you again for the opportunity to appear before the 

Subcommittee on Energy on November 29,2017. 

Sincerely, 

cc; The Honorable Bobby Rush, Ranking Member 

Subcommittee on Energy 

Attachment Enclosed 

CHICAGO lONDON LO$ ANGELES NEW YORK WASHINGTON, DC WWWJENNER.COM 
163 


Max J. Minzner 

Partner, Jenner & Block LLP 

Responses to Questions for the Record 

Committee on Energy and Commerce 

Subcommittee on Energy and Power 

United States House of Representatives 

January 8, 2018 

The Honorable Fred Upton 

I. In terms of enforcement of financial trading, you stated that "financial markets 

inevitably move much faster than regulators. " Is there anything that Congress can 

do to ensure that FERC can remain nimble and be able to evaluate new offerings 

of increasing complex financial products? 

Broadly speaking, FERC has the statutory authority it needs to regulate the financial products in 

its markets. The Federal Power Act provides the Commission multiple options to intervene when 

necessary. First, products generally cannot be traded in the organized markets unless FERC 

approves tariff provisions that permit the transactions. FERC can and should carefully scrutinize 

new offerings to ensure that they improve the functioning of the market. Second, FERC can 

regulate the transactions after they occur by bringing appropriate enforcement actions or 

changing the market rules. Third, market participants can bring complaints if they identify a flaw 

in the market rules. These tools, if used appropriately, should be adequate for the agency to carry 

out its mission. Of course, Congress should ensure that the Commission has adequate resources 

to carry out its mission. 

2. In your testimony, you stated that financial traders should not be treated 

differently just because they are financial, rather than physical, participants in 

the jurisdictional markets. Can you elaborate on this point? 

Market participants should be treated equally and allowed to engage in market transactions on a 

level playing field. Differences in regulatory requirements should depend on risk-based policy 

considerations and should not vary based on the type of market participant. Enforcement actions 

generally should not turn on whether an entity is a physical or financial participant in the market. 

Instead, FERC should focus on the conduct of the enforcement target when bringing an action. 
164 


The Honorable H. Morgan Griffith 

1. As the former General Counsel ofFERC and a Special Counsel in FERC's 

Office ofEnforcement, you've likely seen instances of improper conduct by 

traders of financial products. Now that you are no longer with the 

Commission, can you provide a frank assessment of FERC's abilities to detect 

and investigate improper activity involving financial trading? 

FERC is generally well-equipped with the tools needed to investigate and bring enforcement 

actions in cases involving financial trading. FERC has prioritized the detection of improper 

conduct by developing new algorithmic screens and working to develop other analytic tools. 

These cases are inherently difficult, though, when they involve conduct that crosses jurisdictional 

boundaries. For example, FERC regulates physical energy products while the CFTC regulates 

the financial derivatives that take their value from physical energy. Traders can thus take 

simultaneous positions in linked physical and financial products, only one of which is regulated 

by FERC. Enforcement actions in these cases necessarily involve close coordination between 

sister federal agencies. FERC has historically worked to improve that coordination and should 

continue to do so. 

The Honorable Bj!l Johnson 

1. FERC Commissioner Neil Chatterjee recently stated that one of the Commission's 

priorities moving forward will surround "de novo review." As you may know, the 

majority of current court cases regarding FERC's interpretation have gone on for 

years. Mr. Mizner, do you have any thoughts on bow FERC should address this 

issue? 

The agency is currently litigating the scope of federal court review of enforcement actions under 

the Federal Power Act. So far, district courts have decided that enforcement cases will proceed 

as traditional civil actions under the Federal Rules of Civil Procedure. If this interpretation of the 

FP A ends up being correct, FERC should reexamine its process in enforcement cases. The 

agency needs to carefully balance the procedural protections at the agency with the need to 

expeditiously resolve enforcement matters. If federal court review is likely to be more searching, 

the agency may need to streamline consideration of the actions at FER C. The court decisions 

provide the agency an opportunity to take a fresh look at those processes. 

2 
165 


GREG WALDEN, OREGON 

CHAIRMAN 

Ms. Noha Sidhom 

CEO 

TPC Energy 

ONE HUNDRED FIFTEENTH CONGRESS 

FRANK PALLONE, JR., NEW JERSEY 

RANKING MEMBER 

Ql:onguss of tbe Wntteb ~tates 

~ou!le of l\epre!lentatibe!l 

COMMITTEE ON ENERGY AND COMMERCE 

2125 RAYBURN HousE OFFICE BuiLDING 

WASHINGTON, DC 20515-6115 {202)225-2927 

(202)225-3641 

December 19, 2017 

600 Pennsylvania Avenue, S.E.; Suite 300 

Washington, DC 20003 

Dear Ms. Sidhom: 

Thank you for appearing before the Subcommittee on Energy on November29, 20!7, to testify 

at the hearing entitled "Powering America: Examining the Role of Financial Trading in the Electricity 

Markets." 

Pursuant to the Rules of the Committee on Energy and Commerce, the hearing record remains 

open for ten business days to permit Members to submit additional questions for the record, which are 

attached. The format of your responses to these questions should be as follows: (I) the name of the 

Member whose question you are addressing, (2) the complete text of the question you are addressing in 

bold, and (3) your answer to that question in plain text. 

To facilitate the printing of the hearing record, please respond to these questions with a 

transmittal letter by the close of business on Tuesday, January 9, 2017. Your responses should be mailed 

to Allie Bury, Legislative Clerk, Committee on Energy and Commerce, 2125 Rayburn House Office 

Building, Washington, DC 20515 and e-mailed in Word format to Allie.Bury@mail.house.gov. 

Thank you again for your time and effort preparing and delivering testimony before the 

Subcommittee. 

Sincerely, 

Subcommittee on Energy 

cc: The Honorable Bobby L. Rush, Ranking Member, Subcommittee on Energy 

Attachment 
166 


House Committee on Energy and Commerce 

Subcommittee on Energy 

Powering America: Examining the Role of Financial Trading in the Electricity 

Markets 

Noha Sidhom, CEO, TPC Energy, on behalf of the Power Trading Institute ("PTI") 

Responses for the Record 

1. Financial trading institutions, such as yours, execute financial trades with the 

purpose of making a profit. When your company makes money from a financial 

transaction, such as an FTR, where does your payout come from? Do consumers 

pay for your payout through their electricity bills? 

Consumers do not pay for the payout received by a Financial Transmission Right 

("FTR") owner, if that position is in fact profitable. FTR contracts are settled at the 

wholesale level and not at the retail (consumer) level. That is, sales of FTRs in the 

auctions conducted by the Regional Transmission Organizations/Independent System 

Operators ("RTOs/ISOs") are paid by the purchasing entities, which include, but are not 

limited to, generation ovvners, trading institutions, load serving entities, and private 

investors, and paid to load serving entities who were allocated transmission rights on 

behalf of the consumers they serve. Then, each day, owners of FTRs receive or pay the 

value of congestion determined in the day-ahead wholesale electricity markets conducted 

by the RTOs/ISOs. 

To understand fully the flow of money with respect to FTRs, it is important to 

understand that load serving entities are the wholesale market participants who supply 

power to consumers. What consumers pay for power supply is based upon the terms of 

the contract between each consumer and its respective load serving entity. This type of 

arrangement allows for consumers to choose to be protected from the volatility and 
167 


complexity of wholesale electricity markets, since the load serving entities arc the ones 

who are participating in the wholesale markets, including FTR markets. This type of 

arrangement also allows for consumers to understand how their electricity bills will be 

determined on a forward basis; in other words, it creates certainty for consumers. The 

responsibility of participation, including financial settlement and risk management, in the 

wholesale markets falls squarely on the load serving entity, and unless otherwise agreed 

upon through the contractual arrangement between load serving entities and consumers, 

consumers are not exposed to commercial activity in the wholesale markets. 

The importance of wholesale competitive markets to consumers cannot be 

overstated. The billions of dollars in savings that consumers realize as a result of 

competitive markets can be attributed to, for example, allowing wholesale power 

generation service providers to compete with each other to sell electricity to consumers 

who will buy it at the lowest possible price. These cost-saving benefits to consumers 

have been quantified in a number of studies. In a recent report released by the 

COMPETE Coalition, from 1997 through 2014, prices in consumer-choice jurisdictions 

increased 4.5% less than inflation, while prices in regulated jurisdictions rose 8.4% more 

than inflation.' These results demonstrate significant savings to consumers. 

2. What potential market or regulatory reforms should Congress or FERC be 

considering in order to increase the market benefits associated with financial 

trading? 

PTI makes the following recommendations to both Congress and the Federal 

Energy Regulatory Commission ("FERC" or "Commission"): 

a. FERC should mandate immediate compliance with Order No. 681 and 

ensure that all RTOs/ISOs implement long-term auctions. Long-term 

auctions provide a necessary forward price curve to ensure that the system 

1 O'Connor, P. and O'Connell-Diaz, E., Evolution of the Revolution: The Sustained Success of 

Retail Electricity Competition at 5-7 available at 

https://sites.hks.harvard.edu/hepg!Papers/20 15/Massey Evolution%20of0/o20Revolution.pdf. 
168 


is not overbuilt and consumers are not paying for unnecessary facilities for 

years to come. 

b. FERC should ensure that congestion costs incurred by the market are borne 

by those who cause those costs to be incurred. As discussed in PTI's 

testimony, New York ISO currently allocates congestion costs to 

transmission owners. As a result, New York ISO, unlike every other ISO, 

has very few late scheduled outages or forced outages. New York ISO's 

paradigm provides the appropriate economic incentive for transmission 

owners to manage their outage schedules. Juxtapose this to the California 

ISO, which noted in a recent report that for outages subject to a 30-day 

advance notice requirement under the tariff, about 57% of these outages 

were not submitted to the ISO on time. Specifically, the report noted that in 

PG&E, SCE, and SDGE outages subject to the requirement were not 

received in time 50%, 65%, and 70% of the time, respectively.2 

c. Congress should ensure that the RTOs/ISOs have the most up-to-date 

technology possible to solve their models. 

3. In your testimony, you stated that FTR revenue inadequacy is caused by a market 

design flaw that needs to be resolved. While PJM's Market Monitor has also 

stated that the current market design needs to be reformed, he believes any 

changes should ensure that load receives all congestion revenues. How do you 

respond? 

In a FERC decision on Rehearing dated January 31, 2017, the Commission 

explicitly rejected Dr. Joe Bowring's3 argument that the purpose of FTRs is to return 

congestion revenues back to load. The Commission clearly affirmed its decision on 

Rehearing and stated as follows: 

3 Bowring is President of Monitoring Analytics, PJM's market monitor. 
169 


We reject the arguments that the sole purpose of FTRs is to return 

congestion revenue to load and the market should therefore be redesigned 

to accomplish that directive. FTRs were designed to serve as the financial 

equivalent of firm transmission service and play a key role in ensuring open 

access to firm transmission service by providing a congestion hedging 

function. The purpose of FTRs to serve as a congestion hedge has been 

well established. In the Energy Policy Act of 2005, Congress added section 

217(b)(4) to the FPA,4 directing the Commission to exercise its authority to 

"enable load serving entities to secure firm transmission rights (or 

equivalent tradable or financial rights) on a long-term basis for long-term 

power supply arrangements made, or planned, to meet such needs." In 

Order No. 681, the Commission clearly emphasized the significance of 

FTRs in hedging congestion price risk.5 

Further, FTRs are inextricably linked to the underlying delivery of power to 

customers, and they are integral to shielding consumers from the price volatility that 

comes with having to perfectly balance the grid every minute of the day. The ability for 

load serving entities to shift their risk away from their customers and onto a counterparty 

that is better able to manage that risk is critical for protecting consumers. Without a 

proper forward price curve that is developed by forward congestion values from FTR 

auctions, suppliers, load serving entities, financial participants, and financial institutions 

would have to build in substantial risk premiums in order to be able to take on such 

significant risk without any type of hedging opportunity. This would effectively be a 

dead weight tax on consumers. Therefore, without FTRs, electricity prices would 

undoubtedly increase for ratepayers. 

4 16 u.s.c. § 824q(b)(2)(2012) 5 See PJM Interconnection, L.L.C., Order on Rehearing and Compliance, 158 F.E.R.C., 61,093 

(2017) (quoting Long-term Firm Transmission Rights in Organized Elec. Mkts., Order No. 681, FERC 

Stats. & Regs., 31,226 at P 169, reh ·g denied, Order No. 681-A, 117 FERC, 61,201 (2006), order on 

reh 'g and clarification, Order No. 681-B, 126 FERC, 61,254 (2009)). 
170 


Monitoring Analytics and Dr. Eric Hildebrandt6 both argue that FTRs could be 

traded on a separate exchange, failing to recognize that FTRs are fundamentally linked to 

the day-to-day operations of the grid. The pricing of these rights is utilized in the 

transmission planning process; the number of rights allocated shifts based on the physical 

capability of the grid in a manner only the R"IO/ISO can model and alter. And only the 

RTO/ISO can reconfigure the actual right, meaning they can change the path from A to B 

to A to C, if that is the more appropriate configuration that needs to be priced and 

allocated. In fact, PERC recently opined on the reconfiguration and reallocation of rights 

in PJM. Historical rights that were not reflective of the current transmission system were 

being allocated, causing distortions in the modeling and pricing. PERC mandated that 

PJM update its allocation process to allocate rights based on the current system. 7 Only 

the RTOs!ISOs can model the physical system constraints that will be applicable for the 

period auctioned in order to determine an appropriate price based upon the preferences of 

willing buyers and sellers. 

In addition, FTRs are paid from day-ahead revenue that is not just an exchange of 

money between FTR traders, but rather a blend of complex activity by all market 

participants, including generation owners and load serving entities. An exchange would 

not incorporate this activity. Lastly, the RTOs/ISOs are the only entities that can 

adequately model and address planned outages in their auctions. For example, if line A 

holding 200 MW of capacity is scheduled to be out for maintenance for two weeks next 

month, the ISO is the only one that can prorate the capacity auctioned off next month to 

I 00 MWs, instead of the 200 MW that line would ordinarily provide if it was in service 

all month. This is precisely why the California ISO report noted above discussed the 

importance of timely outage scheduling. 

As a result, taking these products to an exchange separates rational congestion 

management activity from the economic activity to balance supply and demand on the 

6 Hildebrandt serves as market monitor for the California ISO. 7 PJM Interconnection, L.L.C., Order on Rehearing and Compliance, 158 F.E.R.C., 61,093 

(2017). 
171 


transmission grid and would ultimately increase costs for consumers. From a legal 

perspective, such a divided structure would go against the core principles of Order No. 

888,8 the key FERC order instituting open access. Last and most important, the 

Commission was clear that a full redesign of the FTR market is not warranted.9 

In a commodity market, such as electricity, there are natural buyers and natural 

sellers. Financial participants provide a counterparty to those entities and create a liquid 

market for those transactions to occur. As discussed during PTI's testimony, an FTR is a 

fixed for floating swap; meaning Participant A is getting paid to take on the risk, while 

Participant B has chosen to shift that risk to Participant A in exchange for a fixed price. 

Participant A may make or lose money, but Participant B no longer carries that risk. 

Therefore, financial participants shift risk away from load serving entities, which have 

contractual arrangements with consumers, by being a counterparty in these markets. 

As stated in PTI's statement for the record, the forward price signal that FTRs 

provide to the market leads to more efficient infrastructure development. The organized 

markets have to balance the need for additional infrastructure development with the cost 

of congestion. Does it make sense to build a new transmission line or a new plant in a 

particular region or pay for the cost of congestion in that region, if that would overbuild 

the system to the detriment of consumers? The only way to answer that question is to 

have a forward price curve where willing buyers and sellers take on economic risk and 

provide a forward price signal to evaluate the need for such infrastructure. It is important 

to note that the organized markets have not seen load growth over the past several 

8 Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission 

Services by Public Utilities and Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, 

Order No. 888,61 Fed. Reg. 21,540 (May 10, 1996), FERC Slats. & Regs.~ 31,036 (1996). 9 See PJM Interconnection, L.L.C., Order on Rehearing and Compliance, 158 F.E.R.C. ~ 61,093 

(20 17) ("[T]he Market Monitor and Joint State Commissions reiterate the proposal ... that the 

Commission should support a market redesign to ensure loads receive all congestion revenues. We reject 

the arguments that the sole purpose of FTRs is to return congestion revenue to load and the market should 

therefore be redesigned to accomplish that directive."). 
172 


years. 10 Overbuilding the system would thus be an unnecessary cost that consumers 

would bear for decades to come. 

When thinking about how the money flows, it is important to remember that a 

small portion of these rights are actually auctioned off and a large majority is allocated to 

utilities that serve retail customers. In fact, only the excess capacity is auctioned off in 

the FTR auction. These rights in total reflect the expected physical capability of the 

transmission system to deliver electricity; they are finite and their number is determined 

through analyses conducted by the organized markets. These finite rights are allocated to 

the transmission customers, also known as load serving entities, representing consumers 

that have paid for the fixed investment in the transmission system and are thus entitled to 

rights to the electricity transfer capability of this system. Transmission customers are 

allocated a certain number of contracts. How do we determine the value of these 

contracts that are provided to the transmission customer? The value of the allocated 

rights is determined in the open auction. Bilateral contracts are also priced otT of the 

auction price. Basically, this is a public auction of excess capacity. 

When there is no liquidity in the open auction or competition to arrive at an 

efficient price, the value of that contract diminishes because parties build in a risk 

premium. Simply put, without a locational FTR market construct, there is no mechanism 

to price bilateral contracts or allocated rights. 

In short, FTR auctions save consumers money in four key ways: 

They provide an accurate price for the contracts that are allocated to transmission 

customers representing consumers. 

10 See, e.g., PJM Interconnection, L.L.C., Where has Electricity Demand Growth Gone in PJM 

and What are the Implications? (2014), available at 

https:/ lwww.eia.gov/conference/20 14/pdf/presentations/sotkiewicz.odf; see also Analysis Group, 

Electricity Markets, Reliability and the Evolving U.S. Power System 27-28 (2017), available at 

http://www .analysisgroup .com/uploadedfiles/ content/insights/publishi ng/ag_ markets _reliability_ final jun 

e_2017.pdf. 
173 


They provide a price for the congestion on the grid to determine whether or not the 

cost of congestion is a more appropriate investment than the build out of 

additional infrastructure. 

They provide a price signal to lenders financing infrastructure development which 

thus reduces the cost of financing. 

The trading of financial products results in a more competitive, liquid, and 

transparent wholesale electricity market which ultimately leads to reduced costs 

for consumers.11 

4. In your written testimony, you stated that the hardware and software used by the 

RTOs is inadequate and outdated- you provided an example where PJM was a 

week late in solving its FTR auction. Is the solution simply for the RTOs and ISOs 

to focus time and money on this issue, or is something else holding them back? 

PTI does not believe that the RTOs/ISOs have adequately focused on technology. 

More importantly, there is a lack of transparency regarding hardware and software 

upgrades. It would be extremely beneficial for FERC to require each RTO/ISO to file an 

annual report stating which upgrades or improvements have been accomplished and 

which upgrades or improvements are planned for the coming year. Critical information 

regarding model solve time improvements as well as auction time improvements should 

be a strong focus of the reporting requirement. The answer should not be to limit market 

activity, and it is critical for both Congress and FERC to not allow the RTOs!ISOs to 

limit competition under the guise of technological limitations. In other words, financial 

products should not be limited in either implementation of necessary products or in 

volume of current products because the RTOs/ISOs have not adequately maintained their 

systems to meet market participant demands. 

11 See, e.g., Thomas, et al., Electricity Customer Choice in Ohio: How Competition Has 

Outperformed Traditional Monopoly Regulation, Cleveland State University (20 16), available at 

http://engagedscholarship.csuohio.edu/cgi/viewcontent.cgi?article=2420&context=urban facpub; 

Compete Coalition, RTO and ISO Markets arc Essential to Meeting our Nation's Economic, Energy and 

Environmental Challenges (2014). 
174 


5. In your testimony, you recommend that FERC's enforcement office should make 

publicly available the screens they use to identifY targets for investigation. 

However, if FERC reveals its methods to flag misbehavior would this not give bad 

actors a roadmap to avoid FERC's policing of suspicious trading activity? 

PTI does not believe that FERC providing its enforcement screens to the industry 

would provide bad actors with a roadmap to skirt those screens. We believe this is akin 

to stating, inaccurately, that by sharing the law of the land you are providing a roadmap 

for citizens to break such laws. The very opposite is true. Providing the rules forces civil 

discourse regarding the rules, allows others in industry to police for behavior that the 

Commission considers manipulative or similar behavior and assists compliance officers 

in the industry to build better, more comprehensive enforcement programs. 

The FTR forfeiture rule in PJM is a great example of this issue. The FTR 

forfeiture rule is a rule that states that a market participant would have to forfeit profit 

from a long-term position, if that market participant's short-term position impacted the 

pricing of the long-term position. For many years there was a lack of transparency 

regarding application of the rule and the Market Monitor in PJM made this very same 

argument that providing clarity regarding the rule would help market participants avoid 

direct violation of the rule. The Commission opened this issue up for debate and PJM 

stated that the current administration of the rule was punitive and proposed changes in 

accordance with discussions in the stakeholder process. Clear rules for market 

participants and an open dialogue regarding such rules assists both market participants in 

developing more sophisticated compliance programs and FERC enforcement in building 

a better, more constructive enforcement regime. 
175 


GREG WALDEN, OREGON 

CHAIRMAN 

Mr. Vince Duane 

ONE HUNDRED FIFTEENTH CONGRESS 

FRANK PALLONE, JR., NEW JERSEY 

RANKING MEMBER 

q[:ongre~~ of tbe W:ntteb .i>tate~ 

;!,Jou!Se of l\epre55entatttle55 

COMMITTEE ON ENERGY AND COMMERCE 

2125 RA vauRN HousE OFFICE BUILDING 

WASHINGTON, DC 20515-6115 M11jority 

Mmonty 

December 19,2017 

Senior Vice President, Law Compliance and External Relations 

P JM Interconnection 

2750 Monroe Boulevard 

Audubon, PA 19403 

Dear Mr. Duane: 

Thank you for appearing before the Subcommittee on Energy on November 29, 2017, to testifY 

at the hearing entitled "Powering America: Examining the Role of Financial Trading in the Electricity 

Markets." 

Pursuant to the Rules of the Committee on Energy and Commerce, the hearing record remains 

open for ten business days to permit Members to submit additional questions for the record, which are 

attached. The format of your responses to these questions should be as follows: (1) the name of the 

Member whose question you are addressing, (2) the complete text of the question you are addressing in 

bold, and (3) your answer to that question in plain text. 

To facilitate the printing of the hearing record, please respond to these questions with a 

transmittal letter by the close of business on Tuesday, January 9, 2017, Your responses should be mailed 

to Allie Bury, Legislative Clerk, Committee on Energy and Commerce, 2125 Rayburn House Office 

Building, Washington, DC 20515 and e-mailed in Word format to Allie.Bury!ii'maiLhouse.gov. 

Thank you again for your time and effort preparing and delivering testimony before the 

Subcommittee. 

Sincerely, 

cc: The Honorable Bobby L. Rush, Ranking Member, Subcommittee on Energy 

Attachment 
176 


Vincent Duane 

Sr. Vice President. Gen. Co , Compliance & Ext. Relations 

January 9, 2018 

The Honorable Fred Upton, Chairman 

Committee on Energy and Commerce 

Subcommittee on Energy 

2125 Rayburn House Office Building 

Washington, DC 20515-6115 

PJM Interconnection, LL.C. 

2750 Monroe Blvd. 

Audubon, PA 19403 

Re: November 29, 2017 Hearing - Response to Additional Questions for the Record 

Dear Chairman Upton, 

Thank you for the opportunity to testify before the Subcommittee on Energy of the 

Committee on Energy and Commerce of the U.S. House of Representatives on 

November 29, 2017 at the hearing entitled "Powering America: Examining the Role of 

Financial Trading in the Electricity Markets," and for the opportunity to address 

additional questions of subcommittee members. 

Attached are my responses to those additional questions per your letter dated 

December 19, 2017. Thank you and the Subcommittee for your continued time, effort 

and consideration of perspectives offered. Should you have any questions with regard 

to the attached, please do not hesitate to contact me. 

Sincerely, 

Vincent Duane 

cc: The Honorable Bobby L. Rush, Ranking Member, Subcommittee on Energy 

Ms. Allie Bury, Legislative Clerk, Committee on Energy and Commerce 

Attachment: Responses of Vince Duane, Additional Questions for the Record 

{lfv'01424872} 
177 


Attachment 

Responses of Vincent Duane, PJM Interconnection, L.L.C. to 

Additional Questions for the Record Dated December 19, 2017 

Page 1 of 6 

The Honorable Fred Upton 

1. You stated that financial trading in the electricity markets can be "too much 

of a good thing", and that in some circumstances, needs to be prevented if 

the trading does not deliver any efficiencies to the electricity markets. 

a. However, a broader question is whether RTO markets should host 

this type of trading activity at all? Isn't financial trading more 

appropriate on a financial exchange like NYMEX or the 

Intercontinental Exchange (ICE) rather than in a physical RTOIISO 

market? 

RTO markets should host financial trading only to the extent financial trading 

improves the performance of the predominantly physical RTO/ISO markets. 

RTO/ISOs should not, and PJM does not, create financial instruments to attract 

financial trading as an end unto itself or to compete with secondary market 

exchanges or platforms that can and do offer swaps, options and futures contracts 

used to hedge or speculate on PJM forward prices. 

PJM offers two products that have clear financial characteristics- virtual bids/offers 

and financial transmission rights (FTRs). But even these products have unique 

design elements which support and tie them very closely to PJM's physical market 

operations; to wit PJM's commitment, dispatch and delivery of electricity to supply 

load. 

A virtual trade is a forward contract, committing the counterparty to either buy or sell 

electricity the following day at a price to be determined in that day's spot market. 

The obligation associated with a virtual trade (to buy or sell the next day) can be 

settled financially, which is to say, the counterparty need not deliver, or take delivery 

of, physical electricity. An FTR has different tenures (monthly, multi-month and 

annual). PJM's FTR regime (which includes auction revenue rights (ARRs)) offers 

FTR and ARR holders superior efficiency and optionality to manage the risk of 

location a I price differences in electricity as compared to physically firm transmission 

service, which can be curtailed or subject to redispatch. 

{W0142487.2} 
178 


Attachment 

Responses of Vincent Duane, PJM Interconnection, L.L.C. to 

Additional Questions for the Record Dated December 19, 2017 

Page 2 ofS 

As hopefully is evident from the foregoing product descriptions, both virtual trades 

and FTRs are integral to PJM's fundamentally physical operations. This fact was 

recognized by the Commodity Futures Trading Commission (CFTC) in 2013 when it 

granted exemptions to virtual and FTR transactions from potential Commodities 

Exchange Act jurisdiction. With reference to virtual trades, the final order granting 

these exemptions states: 

Although there is an apparent financial settlement nature of virtual 

and convergence bids and offers ... they are inextricably linked to 

the physical delivery of electric energy due to their being subject to 

the same aggregate physical capabilities of the electric energy 

transmission grid as other physical Energy Transactions. 1 

The CFTC proceeding that culminated in the Final Order cited above, is replete with 

evidence showing the association between RTO!ISO financial products and 

RTOIISO operations, the volumetric limit to these products constrained by the 

physical character of each RTOIISO system and the efficiency and convergence role 

these products can provide to RTOIISO market operations. The role that the 

RTOIISO physical system plays to define and constrain the financially settled 

transactions that occur in these markets distinguishes those transactions from those 

occurring in distinct CFTC-regulated secondary market environments. 2 

Finally, I would note that ISO/RTOs, pursuant in part to FERC Order No. 7 41, 3 have 

adopted practices and protections developed in CFTC-regulated markets to manage 

credit, default and potential gaming concerns unique to financial trading. So, while I 

do not believe the types of virtual and FTR transactions offered by PJM could be 

replicated by CFTC-regulated exchanges or swap dealers and brokers, the 

sophisticated protections developed in these environments have been adopted and 

applied with good result in PJM. 

1 Final Order in Response to a Petition From Certain Independent System Operators and Regional 

Transmission Organizations to Exempt Specified Transactions Authorized by a Tariff or Protocol 

Approved by the Federal Energy Regulatory Commission or the Public Utility Commission of Texas From 

Certain Provisions of the Commodity Exchange Act Pursuant to the Authority Provided in Section 4(c)(6) 

of the Act, RIN 3038-AE02, p.32. 

2 While appropriate to examine fundamental premises as part of the hearing record, it should be noted 

that Congress itself acknowledged in Section 1233 of the Energy Policy Act of 2005 (the "native load" 

provisions of "EPACT 2005"), the link among financial transmission rights, service to native load 

customers and the RTO/ISO's planning obligations which work to ensure the value of those rights on a 

long term basis. 

3 Credit Reforms in Organized Wholesale Electric Markets, Order No. 741, 133 FERC 1)61,060 (2010). 

{W0142487.2} 
179 


Attachment 

Responses of Vincent Duane, PJM Interconnection, L.L.C. to 

Additional Questions for the Record Dated December 19, 2017 

Page 3 of6 

2. PJM's Independent Market Monitor has taken the position that the current 

FTR market design is flawed and does not ensure that load serving entities 

receive all the congestion revenues. Does PJM share the position of its 

independent market monitor? 

PJM does not agree that its current FTR market design is flawed. We do, however, 

agree that the FTR market is not designed to ensure that load serving entities 

receive all congestion revenues. The market is designed to afford load serving 

entities entitled to an allocation of FTRs (or to be more technical, an allocation of 

auction revenue rights) the opportunity to hedge congestion risk associated with 

deliveries from generation to load. 

The allocation of financial rights (FTR/ARRs) serves as the paradigm in organized 

wholesale electricity markets by which the ISO/RTO, as transmission provider, 

meets its obligations to provide to customers open access firm transmission service. 

In non-market regions of this country, transmission customers take physically firm 

service. Importantly, physically firm transmission service does not mean a 

transaction cannot be curtailed, subject to TLRs, or redispatch costs. In theory, 

transmission service providers (both those providing financial rights and those 

providing physical rights) can reduce or eliminate altogether instances where either 

the financial rights allocation fails to hedge all congestion exposure or where 

physical rights have to be curtailed, respectively. This outcome can be achieved by 

applying very conservative estimates of the available capacity on the transmission 

system in deciding on the number of FTR/ARRs to offer or the number of physical 

transmission service requests to approve, respectively. 

While such conservatism can assure that an FTR fully offsets congestion cost or that 

a physical transaction is never curtailed, this overly-cautious approach would 

effectively discount the real transfer capability of the respective system under normal 

and reasonably foreseeable system conditions. In effect, this overly cautious 

approach underutilizes the system and will result in a suboptimal level of 

transmission transactions relative to the capability of the system. 

As is equally true for traditional physical transmission service providers, the only way 

to offer a customer an absolute guarantee of firm service would be to grant an 

unreasonably low level of transmission service requests. Consequently, when 

Congress addressed financial transmission rights in EPACT 2005, it made clear that 

transmission customers under an FTR/ARR regime are entitled to financial 

transmission rights to meet their "reasonable" load serving needs. 

Finally, in PJM the highest priority of financial rights is allocated to load serving 

entities on paths aligned with physical energy deliveries. After first allocating 

financial rights requested by load serving entities, excess capability may be 

{W0142487.2} 
180 


Attachment 

Responses of Vincent Duane, PJM Interconnection, L.L.C. to 

Additional Questions for the Record Dated December 19, 2017 

Page 4 of 6 

purchased by non-load serving entities. Excess capability is historically available 

only on those paths not aligned with congestion patterns. Therefore, typically where 

a non-load serving entity acquires rights on a path associated with physical energy 

delivery, it will pay a premium for these rights. This premium benefits the market by 

increasing revenues to all ARR holders, including load serving entities 

The Honorable John Shimkus 

1. In answering my question regarding the degradation of firm transmission 

rights when the transfer from physical rights to FTRs occurred more than a 

decade ago, you stated that some entities ultimately were not hedged as 

they might have been otherwise. The Federal Power Act requires the FERC 

assure that RTOs reasonably plan and expand your transmission system to 

meet the foreseeable needs of Load Serving Entities. That planning 

includes the allocation of physical transmission rights (or at least 

equivalent financial rights) on a long term basis for LSEs that have long 

term power supply arrangements. Isn't it reasonable that entities that had 

long term firm transmission rights be held harmless by your tariffs? At a 

minimum, shouldn't your system provide them equivalent or comparable 

access to their resources without excessive congestion cost if they 

originally had a long term firm transmission path? If not, how is your 

market design just and reasonable if it causes costs or price escalation for 

resources owned by entities that held long term firm transmission rights? 

Answer 

Long term firm transmission customers in PJM are allocated ARRs recognizing 

these customers paid originally for transmission for their load to access resources. 

When PJM's energy market prices separate, which is to say prices at the where 

power is injected differ from the where power is withdrawn, the transmission 

customer is exposed to congestion - a higher locational price at the delivery point as 

compared to the price realized by the generator at the point of injection. A 

transmission customer can hedge this price differential by holding an FTR on the 

pathway between these locations. The FTR is funded by congestion revenues 

collected by PJM. 

A transmission customer is first allocated a level of ARRs in an amount 

commensurate to its transmission service, and subject to PJM's transfer capability 

modeling described in my response to the second question above. A customer can 

elect to convert its ARRs into FTRs and can {subject to caveat mentioned in the 

response above) thus deliver energy effectively congestion free from its historic 

{W0142487.2} 
181 


Attachment 

Responses of Vincent Duane, PJM Interconnection, L.L.C. to 

Additional Questions for the Record Dated December 19, 2017 

Page 5 of6 

resources to its load. Additionally, however, PJM's financial rights regime works 

such that if the transmission customer elects not to convert its ARRs into FTRS, it 

will instead receive the revenues realized by selling these FTRs in PJM administered 

auctions. Giving a transmission customer this optionality permits them to monetize 

FTRs they would otherwise hold if the customer believes other market participants in 

PJM place a greater value, and thus will pay more, than what the transmission 

customer believes the FTR is worth. Customers that take this route may realize 

revenues in excess of the congestion costs they end up being exposed to. But the 

other side of the bet also exists. By assuming the floating price risk of congestion in 

return for fixed revenues coming out of the FTR auction, the customer may not be 

fully hedged to actual congestion costs as they occur. Depending on system 

conditions and resulting levels of congestion, the customer thus may end up paying 

more in congestion than it received by way of auction revenue rights. This outcome, 

of course, is the result of the customer's financial decision, and is not a pre-ordained 

consequence of PJM's market design. 

Your question references the obligations imposed by the Federal Power Act to plan 

and enhance the transmission system in order to meet a long-term, firm customer's 

reasonable needs. The scope and interpretation of this standard has been subject 

to debate before FERC. A particular question as to how the law defines a 

customer's "reasonable needs" was addressed by the FERC in Order No. 681.4 In 

this Order, FERC provided a guideline which stated that "transmission organization 

may propose reasonable limits on the amount of existing capacity used to support 

long-term firm transmission rights such as minimum daily peak load or 50 percent of 

maximum daily peak load." In PJM compliance filings made pursuant to the final 

rule, certain parties protested that "reasonable needs" for purposes of FTRs should 

mean whatever a customer may need at any point in time to deliver energy to load. 

PJM instead proposed a standard it describes as the customer's "zonal base load," 

which conforms to the minimum daily peak load guidance offered by the FERC in 

Order No. 681. PJM's standard was ultimately accepted by FERC over objection by 

certain customers with the Commission reasoning that PJM's proposal met the 

requirements of both Order No. 681 and the Federal Power Act's "reasonable 

needs" standard. 

Importantly, once this standard is triggered, PJM is required by law to expand its 

transmission system, as correctly noted in your question. Recently, in order to 

ensure that a legally sufficient allocation of ARRs could be maintained to 

transmission customers in Illinois, PJM ordered development and construction of a 

345kV transmission project, known as the Grand Prairie Gateway Project, to 

enhance congestion free transfer capabilities in the Commonwealth Edison zone, for 

the benefit of long term transmission customers in that zone. This project offers an 

excellent illustration of how Congress' EPACT 2005 amendments to the Federal 

4 See Long-Term Firm Transmission Rights in Organized Electricity Markets, Order No. 681, 116 FERC 

1161,077 (2006). 

{W0142487.2} 
182 


Attachment 

Responses of Vincent Duane, PJM Interconnection, L.L.C. to 

Additional Questions for the Record Dated December 19, 2017 

Page 6 of6 

Power Act work to provide long term transmission customers in PJM an appropriate 

degree of congestion hedge while not subjecting all customers to inefficient and 

expensive overbuilding of the transmission network. The "reasonable needs" 

standard adopted by EPACT 2005 appropriately balances the needs of an individual 

customer while ensuring just and reasonable rates for the broader set of 

transmission customers. 

{W0142487.2} 
183 


GREG WALDEN, OREGON· 

CHAIRMAN 

FRANK PALLONE, JR., NEW JERSEY 

RANKING MEMBER 

Mr. Chris Moser 

ONE HUNDRED FIFTEENTH CONGRESS 

ctCongrr~~ of tbt Wntttb ~tate~ 

~ousc of l\epnsentattbes 

COMMITTEE ON ENERGY AND COMMERCE 

2125 RAYBURN HousE OFFICE BuiLDING 

WASHINGTON, DC 20515-6115 {202)225-2927 

(202)225---3641 

December 19,2017 

Senior Vice President of Operations 

NRG Energy 

804 Carnegie Center 

Princeton, NJ 08540 

Dear Mr. Moser: 

Thank you for appearing before the Subcommittee on Energy on November 29, 2017, to testify 

at the hearing entitled "Powering America: Examining the Role of Financial Trading in the Electricity 

Markets." 

Pursuant to the Rules of the Committee on Energy and Commerce, the hearing record remains 

open for ten business days to permit Members to submit additional questions for the record, which are 

attached. The format of your responses to these questions should be as follows: (I) the name of the 

Member whose question you are addressing, (2) the complete text of the question you are addressing in 

bold, and (3) your answer to that question in plain text. 

To facilitate the printing of the hearing record, please respond to these questions with a 

transmittal letter by the close of business on Tuesday, January 9, 2017. Your responses should be mailed 

to Allie Bury, Legislative Clerk, Committee on Energy and Commerce, 2125 Rayburn House Office 

Building, Washington, DC 20515 and e-mailed in Word format to Allie.Burv(i:i•mail.house.gov. 

Thank you again for your time and effort preparing and delivering testimony before the 

Subcommittee. 

Sincerely, 

: 

cc: The Honorable Bobby L. Rush, Ranking Member, Subcommittee on Energy 

Attachment 
184 


VIA OVERNIGHT & ELECTRONIC MAIL 

Allie Bury 

Legislative Clerk 

Committee on Energy and Commerce 

2125 Rayburn House Office Building 

Washington, D.C. 20515 

Dear Ms. Bury: 

January 8, 2018 

NRG Energy, Inc. 

804 Carnegie Center 

Princeton, NJ 08540 

Attached please find responses to Chairman Upton's December 19, 2017 follow-up questions 

to my testimony before the Subcommittee on Energy hearing on November 29, 2017 entitled 

"Powering America: Examining the Role of Financial Trading in Electricity Markets." 

Enclosure 

Sincerely, 

Is/ Christopher Moser 

Christopher Moser 
185 


Attachment- Responses to Additional Questions for the Record 

1. Can you explain how you use FrRs to keep prices low for NRG's consumers? 

NRG utilizes Financial Transmission Rights, or FTRs, in three primary ways: 

Retail Power Sales: 

NRG purchases FTRs to hedge its retail sales of power. In the organized RTO/lSO electricity 

markets, there can be significant differences in the price we: (i) receive for sales from our power plants 

and (ii) pay to purchase power needed to serve our retail load obligations. These price differentials 

result from the fact that NRG' s generation resources or power purchases are not always co-located 

with the customers we serve, which exposes NRG to the risk of congestion on the transmission system. 

Electricity costs more to make and deliver in crowded (or "congested") areas of the grid, such as large 

cities or areas that are far from generation. 

NRG utilizes FTRs to manage this risk and provide predictable and stable prices to its end-use 

customers. Specifically, NRG can purchase an FTR along the path between a generating facility (or, 

more likely, a liquid point on the system, usually known as a "hub") and its end-use customers. For 

example, New York City's electric grid is as congested as its roadways. So ifNRG sells electricity to 

a customer in the middle of New York City from a power plant located in upstate New York, it is 

likely that the transaction will incur additional congestion charges. Without FTRs, it would be difficult 

to predict exactly how much we would pay in extra congestion charges and we would have to include a 

larger "risk premium" in our prices to account for that uncertainty. A higher risk premium directly 

increases the price paid by end-use consumers. Purchasing an appropriate FTR, however, allows the 

parties to "lock in" those congestion charges, eliminating much of the congestion risk in exchange for 

an upfront payment. 

Of course, purchasing FTRs costs money, which may reduce the profits we would otherwise 

earn. But the tradeoff is that we will not lose large amounts of money if unexpected congestion 

appears on the system. Overall, FTRs allow NRG to protect against unpredictable congestion on the 

transmission system, minimize the costs to retail customers, and increase our ability to offer customers 

long-term, fixed-price power deals. 

Wholesale Power Sales: 

FTRs are also critical to the process of selling our generation output to other retailers of 

electricity. For example, NRG often sells power from its power plants on a bilateral basis to other 

companies, who then re-sell the power to end-use consumers. The organized electricity markets 

facilitate these bilateral sales by providing both parties with open access to the transmission system 

and clear, transparent prices. 

Whether the buyer or seller takes the risk of congestion is often a significant negotiating point. 

Sellers of power typically prefer that all risk of congestion (or even outright failure of the transmission 

system) transfer to the buyer at the point where the power plant injects the power into the grid. 

Buyers, on the other hand, typically prefer that the seller maintain the risk of successfully delivering 

the power. FTRs allow either party to manage the risk of transmission congestion by buying an FTR. 

If the sale of electricity is ultimately accompanied by any additional congestion costs, then the FTR 

makes the parties whole for those costs. Thus, FTRs provide an "insurance policy" against the risk 
186 

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that congestion will appear on the system and substantially alter the economics of the underlying 

transaction. 

FTRs are particularly important when selling the output of large-scale renewable generators, 

which are often located far from load. In many cases, generators located far from load are subject to 

increased risk of congestion between the point of injection into the power grid and the point of delivery 

to an end-use customer. FTRs protect both sides of the transaction from congestion risk, which 

facilitates stable prices for both buyers and sellers of renewable power. 

Transmission System Investments: 

FTRs can be a powerful means of attracting additional at-risk capital into the transmission 

system, which is typically dominated by utility investment using captive ratepayer dollars. Most 

organized markets permit non-utilities to pay to upgrade an "element" of the transmission system that 

constricts the flow of power from Point A to Point B. In exchange for fronting the capital to make or 

advance the construction of the upgrade, the investor receives the value of any additional power flows 

across that element, usually in the form of FTRs or related products. Thus consumers receive new or 

accelerated improvements to the transmission system, while investors only make money to the extent 

the new/upgraded transmission improvement is actually used. This moves risk from captive customers 

to private investors, while increasing total infrastructure investment. 

2. As a merchant utility with actual generating assets and retail customers, can you explain why 

and how NRG uses virtual transactions? 

NRG likewise uses virtual transactions to manage sales from its power plants and to manage 

retail market positions. Virtual transactions are a powerful tool for managing the risk inherent in twosettlement electricity markets, where some power sales take place in the day-ahead market (the first 

settlement), and other sales take place in the real-time market (the second settlement). Prices can 

diverge between day-ahead and real-time markets as physical conditions on the grid evolve over time. 

These price differences are critical to the proper functioning of electricity markets, and are often 

caused by changing load forecasts (i.e., as we get closer to real-time, we better understand consumer 

demand, based on weather and other factors), changes in generator or transmission line outages, 

changing fuel costs, or other factors. 

As a result, it is often more or less advantageous to sell (or purchase) power in either the dayahead or real-time markets. Virtual transactions allow generators to pay a (usually small) fee to 

"virtually" shift their sales of power from the day-ahead to the real-time market, if conditions warrant.