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62–705 PDF 2010

S. HRG. 111–752 

FINANCIAL DERIVATIVES ON ENERGY MARKETS 

HEARING 

BEFORE THE

COMMITTEE ON 

ENERGY AND NATURAL RESOURCES 

UNITED STATES SENATE 

ONE HUNDRED ELEVENTH CONGRESS 

SECOND SESSION 

TO

EXAMINE FINANCIAL TRANSMISSION RIGHTS AND OTHER ELECTRICITY 

MARKET MECHANISMS 

MARCH 9, 2010 

( 

Printed for the use of the 

Committee on Energy and Natural Resources 
(II) 

COMMITTEE ON ENERGY AND NATURAL RESOURCES 

JEFF BINGAMAN, New Mexico, Chairman 

BYRON L. DORGAN, North Dakota 

RON WYDEN, Oregon 

TIM JOHNSON, South Dakota 

MARY L. LANDRIEU, Louisiana 

MARIA CANTWELL, Washington 

ROBERT MENENDEZ, New Jersey 

BLANCHE L. LINCOLN, Arkansas 

BERNARD SANDERS, Vermont 

EVAN BAYH, Indiana 

DEBBIE STABENOW, Michigan 

MARK UDALL, Colorado 

JEANNE SHAHEEN, New Hampshire 

LISA MURKOWSKI, Alaska 

RICHARD BURR, North Carolina 

JOHN BARRASSO, Wyoming 

SAM BROWNBACK, Kansas 

JAMES E. RISCH, Idaho 

JOHN MCCAIN, Arizona 

ROBERT F. BENNETT, Utah 

JIM BUNNING, Kentucky 

JEFF SESSIONS, Alabama 

BOB CORKER, Tennessee 

ROBERT M. SIMON, Staff Director 

SAM E. FOWLER, Chief Counsel 

MCKIE CAMPBELL, Republican Staff Director 

KAREN K. BILLUPS, Republican Chief Counsel 
(III) 

C O N T E N T S 

STATEMENTS 

Page 

Bingaman, Hon. Jeff, U.S. Senator From New Mexico ........................................ 1 

Brown, Garry, Chairman, New York State Public Service Commission, on 

behalf of the National Association of Regulatory Utility Commissioners ....... 20 

Duane, Vincent P., Vice President and General Counsel, PJM Interconnection, 

L.L.C., Norristown, PA ........................................................................................ 24 

Gensler, Gary, Chairman, Commodity Futures Trading Commission ................ 14 

Henderson, Michael W., Vice President & Chief Financial Officer, Arkansas 

Electric Cooperative Coporation, Arkansas Electric Cooperatives, Inc., Little 

Rock, AR ............................................................................................................... 43 

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

FPL Group, Inc., on behalf of the Edison Electric Institute and the Electric 

Power Supply Association .................................................................................... 34 

Murkowski, Hon. Lisa, U.S. Senator From Alaska ............................................... 2 

Wellinghoff, Jon, Chairman, Federal Energy Regulatory Commission ............... 3 

APPENDIXES 

APPENDIX I 

Responses to additional questions .......................................................................... 57 

APPENDIX II 

Additional material submitted for the record ........................................................ 81 

(1) 

FINANCIAL DERIVATIVES ON ENERGY 

MARKETS 

TUESDAY, MARCH 9, 2010 

U.S. SENATE, 

COMMITTEE ON ENERGY AND NATURAL RESOURCES, 

Washington, DC. 

The committee met, pursuant to notice, at 10:03 a.m., in room 

SD–366, Dirksen Senate Office Building, Hon. Jeff Bingaman, 

chairman, presiding. 

OPENING STATEMENT OF HON. JEFF BINGAMAN, U.S. 

SENATOR FROM NEW MEXICO 

The CHAIRMAN. OK. Why do we not get started? Let me start by 

welcoming our witnesses. 

In the 110th Congress, an issue arose of the question of overlap 

of jurisdiction between the Commodity Futures Trading Commission over futures instruments and the new authority that Congress 

had given to FERC over market manipulation and regulated electricity markets. We thought that that issue had been resolved with 

the colloquy on the floor and with report language that we—at 

least I read to clarify that there was no intent for CFTC to take 

over regulation of matters that had been jurisdictional at FERC 

under the Federal Power Act and the Natural Gas Act. 

We come to this point with new legislation that has been passed 

in the House, may be considered here in the Senate in the coming 

months, that many tell us would make the problems that FERC 

has in controlling markets under its purview more difficult. 

For several years now, many in Congress have been criticizing 

regulatory agencies, CFTC as well as others, for not regulating derivatives closely enough and thereby allowing speculation to play 

too large a role although many have laid some of the blame for the 

collapse of financial markets on lax regulation allowing dangerous 

dependence on derivatives, but now we have a more aggressive approach, which is welcomed by the CFTC, to financial instruments. 

Many of us are concerned that this perhaps, at least, should not 

apply to things in electricity markets that have traditionally been 

regulated by FERC. I think there is a difference. FERC regulates 

electricity markets and the instruments that are used in those 

markets under the Federal Power Act. The Federal Power Act is 

concerned about rates. Rates and contracts must be just and reasonable and not unduly discriminatory or preferential. I think that 

is a key aspect of what FERC’s responsibility is. 
2 

The standard under which CFTC regulates derivatives and futures contracts has to do with orderly markets that are not manipulated. It does not have to do with the reasonableness of rates. 

We seem to be presented with 2 choices: create a bright line between the jurisdiction of the 2 agencies or allow the CFTC to decide what falls into its scope exclusively, thus becoming, in effect, 

the arbiter of FERC jurisdiction under its organic statutes. There 

may be other alternatives that I am not thinking of, and we would 

be anxious to hear about that. 

So these are the questions that are in my mind as we approach 

the hearing. I think this is a difficult matter that Congress needs 

to try to understand before we legislate in this area. 

Let me defer to Senator Murkowski for her comments. 

STATEMENT OF HON. LISA MURKOWSKI, U.S. SENATOR 

FROM ALASKA 

Senator MURKOWSKI. Thank you, Mr. Chairman. I would like to 

welcome not only the 2 chairmen this morning for taking time out 

of your busy schedules to appear before us today but those that will 

appear on the second panel as well. 

I have been amazed for about the past year with the number of 

people that I have met in this Congress that say that the one thing 

that they are looking for from the Federal Government is certainty. 

It does not matter whether we are talking about climate change, 

whether we are talking about energy legislation, or banking reform. Stakeholders need to understand what the rules are so that 

they can plan accordingly and they can abide by them. 

I often suggest that the one thing that we do pretty well is implement the law of unintended consequences. As the Senate considers 

Wall Street reform legislation, we know that our legislative actions 

to regulate over-the-counter derivatives will have consequences for 

physical energy markets. You get asked the question how do we 

know this? It is because today we are also receiving testimony from 

the State regulators, a united industry, everyone from utilities, 

independent electricity generators, renewable energy providers. 

They are warning us that our actions could not only create regulatory uncertainty but they could result in significant increases for 

electricity prices. 

As the Senate works on Wall Street reform legislation, we can 

all agree that Congress must guard against a systemic risk by improving the oversight, the transparency, and the stability of financial markets. 

The CFTC will certainly be provided with additional regulatory 

authority aimed at addressing systemic risk in the OTC market, 

but we need to carefully tailor congressional action to avoid sweeping in the physical energy markets that are regulated by the 

FERC. We do not want to be in a situation where we have wellintentioned legislation that results in burdensome, duplicative, or 

conflicting regulatory requirements for critical power transactions. 

The resulting ambiguity does nothing to increase transparency in 

the markets and could, instead, lead to both gaming and forum 

shopping. 

We are already seeing where a jurisdictional dispute between the 

2 agencies is leading to market uncertainty. The financial trans-
3 

mission rights, or the FTRs, are used to hedge against volatile 

transmission prices and are currently solely regulated by the 

FERC. This is a point that the committee reinforced in the 2005 

Energy Policy Act. 

In the 2008 Farm Bill, Congress tried to maintain the existing 

jurisdictional lines between the CFTC and the FERC, but despite 

these efforts, the CFTC is now considering whether some transactions within the organized wholesale electric markets like the 

FTRs are subject to its exclusive jurisdiction under the Commodity 

Exchange Act. 

I think it is important to note that these 2 agencies have very 

different missions. FERC is tasked with ensuring just and reasonable electricity rates for consumers, along with reliable delivery of 

power. In contrast, the CFTC is charged with policing the markets 

for fraud, manipulation, and abuse. I think it is important that we 

keep these different goals in mind as we work on financial reforms. 

Now, we recognize, Mr. Chairman, that the Energy Committee is 

not the lead on Wall Street reform efforts, but I am pleased that 

many of our members have vested interest in this debate, Senator 

Corker is involved with the Banking Committee and Senator Lincoln, of course, as chairman of the Agriculture Committee. I am 

confident that we can work collaboratively on these jurisdictional 

issues in order to maintain just and reasonable electricity prices for 

our consumers. 

I look forward to the comments that we will hear this morning. 

The CHAIRMAN. Let me just mention here at the beginning that 

we have an awkward circumstance which is fairly common here in 

the Senate, that we have 4 votes starting at 11 o’clock. So what I 

have indicated to both Chairman Wellinghoff and Chairman 

Gensler is that I would like, if they would, to have them go ahead 

and testify, give us their views, and then maybe we could ask them 

to have a seat in the audience and bring forward the other 4 panelists for the second panel and have them give their views. Only 

after we have heard from all 6 witnesses would we start our questions. That way if we have to quit, which we will have to in about 

an hour, we will not be denying anyone the right to testify. 

So we do have our first panel here: the Honorable Jon 

Wellinghoff, who is Chairman of the Federal Energy Regulatory 

Commission, and the Honorable Gary Gensler, who is Chairman of 

the Commodity Futures Trading Commission. We welcome you 

both and appreciate you coming. Chairman Wellinghoff, why do 

you not go ahead and then Chairman Gensler. 

STATEMENT OF JON WELLINGHOFF, CHAIRMAN, FEDERAL 

ENERGY REGULATORY COMMISSION 

Mr. WELLINGHOFF. Thank you, Chairman Bingaman and Ranking Member Murkowski, and Senator Corker. Thank you for the 

opportunity to appear here today. 

In the interest of time, Mr. Chairman, I would request that my 

prepared written statement be entered into the record, and I will 

summarize my testimony. 

The CHAIRMAN. We will include every witnesses’ full statement 

in the record, and we will appreciate if you can make the main 

points that you think we need to understand. 
4 

Mr. WELLINGHOFF. My testimony will address the energy markets regulated by FERC and how they may be affected by current 

or proposed laws focused on financial derivatives. I will explain 

why consumers could face higher energy costs if FERC’s role and 

authority in these markets is reduced by laws addressing financial 

derivatives. 

The Commodity Futures Trading Commission regulates certain 

financial derivatives under existing law and would regulate additional financial derivatives under H.R. 4173, the Wall Street Reform and Consumer Protection Act of 2009. FERC and the CFTC 

have different missions. FERC is a rate regulator and ensures that 

rates charged to energy customers are just and reasonable. FERC 

also approves and enforces electric reliability standards. The CFTC 

seeks to ensure that markets are generally operated fairly and orderly, but has neither the authority nor the expertise to ensure the 

reasonableness of rates or oversee reliability of energy supplies. 

Shifting jurisdiction over energy markets from FERC to the CFTC 

would impair FERC’s ability to protect energy consumers from unreasonable energy rates, an especially important consideration during our economic times. Similarly, expanding the CFTC’s authority 

in FERC-regulated markets could limit FERC’s ability to police 

against market manipulation in energy markets. 

In fiscal year 2009, FERC’s efforts against market manipulation 

and other types of violations led to $38 million in civil penalties 

and $38 million in disgorgement. The scope of future efforts by 

FERC could be narrowed under the provisions such as those in 

H.R. 4173. 

Also, uncertainty about regulatory authority and rules in energy 

markets could chill investment or increase the cost of capital investments, ultimately harming consumers. This uncertainty could 

also slow investments in green energy such as renewable resources. 

The impetus for legislation on derivatives is from the financial 

turmoil caused by certain unregulated financial derivatives and 

other factors. The FERC-regulated markets did not cause these 

problems. Thus, whatever decisions Congress makes for currently 

unregulated financial derivatives should not apply to the energy 

markets regulated comprehensively by FERC. Any amendments to 

the Commodity Exchange Act should preserve FERC’s exclusive 

oversight of rates, terms and conditions for energy transportation 

and wholesale sales, and prevent dual regulation of energy markets 

by FERC and the CFTC. Alternatively, FERC’s jurisdiction can be 

maintained through appropriate amendments to the Federal Power 

Act and the Natural Gas Act. Either way, legislation on financial 

derivatives should not impair FERC’s ability to ensure that consumers have a dependable supply of energy at just and reasonable 

rates. 

Any appropriate improvements to the rules for FERC-regulated 

markets can be made by FERC and do not require a shift in authority to another agency. For example, 2 months ago, FERC proposed to require several actions to strengthen credit rules in RTO 

and ISO markets. The proposed actions include reducing or eliminating the use of unsecured credit in those markets and shortening 

the time allowed for posting of additional collateral. In a separate 
5 

action, the commission asked for comments on whether to require 

comprehensive reporting of resales of FTRs in secondary markets. 

So while I and others continue to seek improvement in these 

markets, I see no problem in these markets that would be solved 

by reducing FERC’s authority in the energy markets. No regulatory 

failure has occurred that would warrant such a major shift in oversight of these markets. These markets are vital in meeting the energy needs of millions of Americans, and nothing has been identified that warrants the uncertainty of inserting a new regulator and 

a new regulatory regime. 

The potential harm from taking regulation of the energy markets 

away from FERC would be substantial. Investment and infrastructure needed to both maintain reliability and to develop clean, renewable energy resources could be impeded. Consumer protection 

could be impaired, and the benefits to consumers from viable competitive energy markets could be compromised. 

In short, the current system of FERC oversight and comprehensive regulation of electric and gas markets is working well. Changing that system will not enhance benefits to consumers but only 

put them in jeopardy. 

Thank you for holding this important hearing and for inviting me 

to speak here today, and I would be happy to answer questions 

after the other panels come up. Thank you, Mr. Chairman. 

[The prepared statement of Mr. Wellinghoff follows:] 

PREPARED STATEMENT OF JON WELLINGHOFF, CHAIRMAN, FEDERAL ENERGY

REGULATORY COMMISSION

INTRODUCTION

Mr. Chairman, Ranking Member Murkowski and members of the Committee: 

Thank you for the opportunity to appear before you today. My testimony will address the energy markets regulated by the Federal Energy Regulatory Commission 

(FERC), and how they may be affected by current or proposed laws focused on financial derivatives. I will explain why consumers could face higher energy costs if 

FERC’s role and authority in these markets is reduced by laws addressing financial 

derivatives. 

The Commodity Futures Trading Commission (CFTC) regulates certain financial 

derivatives under existing law, and would regulate additional financial derivatives 

under H.R. 4173, the Wall Street Reform and Consumer Protection Act of 2009. 

FERC and the CFTC have different missions. FERC is a rate regulator and ensures 

that rates charged to energy customers are just and reasonable. FERC also approves 

and enforces electric reliability standards. The CFTC seeks to ensure that markets 

generally operate fairly and orderly, but has neither the authority nor the expertise 

to ensure the reasonableness of rates or oversee reliability of energy supplies. Shifting jurisdiction over energy markets from FERC to the CFTC could impair FERC’s 

ability to protect consumers from excessive energy rates, an especially important 

consideration during a recession. Similarly, expanding the CFTC’s authority in 

FERC-regulated markets could limit FERC’s ability to police against market manipulation in energy markets. 

Also, uncertainty about regulatory authority and requirements in energy markets 

could chill investments or increase the cost of capital for infrastructure investments, 

ultimately harming consumers. This uncertainty also could slow investments in 

‘‘green energy,’’ such as renewable resources and smart grid technology. 

The impetus for legislation on financial derivatives is the financial turmoil caused 

by certain unregulated financial derivatives and other factors. The FERC-regulated 

markets did not cause these problems. Thus, whatever decisions Congress makes for 

currently-unregulated financial derivatives should not apply to the energy markets 

regulated comprehensively by FERC. Any amendments to the Commodity Exchange 

Act should preserve FERC’s exclusive oversight of rates, terms and conditions for 

energy transportation and wholesale sales, and prevent dual regulation of energy 

markets by FERC and the CFTC. Alternatively, FERC’s jurisdiction can be main-
6 

tained through appropriate amendments to the Federal Power Act and the Natural 

Gas Act, and I would encourage the Committee to consider this approach. 

As my colleague, Chairman Gensler, testified recently to the House Committee on 

Agriculture about certain financial markets: ‘‘While seeking to address the gaps and 

inconsistencies that exist in the current regulatory structure of complex, consolidated financial firms, the proposals also may have unintentionally encompassed 

robustly regulated markets. . . .’’ Similarly here, legislation by Congress on financial derivatives should not impair FERC’s ability to ensure that consumers have an 

adequate supply of energy at just and reasonable rates. 

BACKGROUND

Since the late-1970s, Congress and FERC have encouraged competition in the natural gas and electricity industries. In the natural gas industry, Congress adopted 

the Natural Gas Policy Act of 1978 and the Natural Gas Wellhead Decontrol Act 

of 1989, removing price controls on first sales of natural gas. FERC also adopted 

pro-competitive regulations, particularly Order No. 636, requiring the interstate 

pipelines to unbundle their sales and transportation services. 

In the electric industry, this effort has included legislation such as the Public 

Utility Regulatory Policies Act of 1978 (facilitating market entry by combined heatand-power facilities and small renewable energy facilities), the Energy Policy Act of 

1992 (expanding FERC’s authority to require transmission service upon customer 

application, and reducing barriers to entry by independent power producers) and the 

Energy Policy Act of 2005 (reducing barriers to investment in the industry, subject 

to protection against cross-subsidization by ratepayers). 

The Commission’s efforts in the electric industry include the landmark Order No. 

888, issued in 1996. Order No. 888 required public utilities to offer transmission 

service to others on non-discriminatory rates, terms and conditions. Order No. 888 

also encouraged the formation of independent system operators (ISOs), to operate 

all of the transmission facilities in a geographic area. ISOs were aimed at encouraging competition by facilitating development of regional power markets, and enhancing trading opportunities for a region’s buyers and sellers. Several years later, 

FERC’s Order No. 2000 encouraged the formation of regional transmission operators 

(RTOs), which perform the same transmission functions as ISOs but generally are 

larger in geographic scope. Today, RTOs and ISOs operate not only transmission facilities but also markets for trading electric energy among utilities. 

RTO and ISO power markets and transmission services are tightly integrated, 

and regulated to a greater extent than most other markets. The rules for RTO and 

ISO markets are specified in lengthy tariffs (hundreds or thousands of pages) reviewed and approved by FERC. In order to analyze these tariffs, the Commission 

draws upon expertise in various disciplines, including attorneys, economists, energy 

industry analysts, and engineers. The tariffs contain numerous requirements and 

mechanisms to ensure reasonable rates and a reliable supply of electricity. These 

rules are carefully designed to facilitate competitive forces within a heavily-regulated industry. The RTOs and ISOs themselves are not ‘‘self-regulating organizations,’’ but are legally considered to be ‘‘public utilities’’ and in fact are regulated 

more extensively than other public utilities. 

Generally, the Commission’s responsibility in the energy industries is to ensure 

that consumers have adequate supplies of energy at reasonable prices. For example, 

Federal Power Act sections 205 and 206 require the Commission to ensure that the 

rates, terms and conditions offered by RTOs, ISOs and other public utilities are just, 

reasonable and not unduly discriminatory. This responsibility applies to wholesale 

sales and transmission of electricity in interstate commerce, as well as contracts or 

other arrangements and practices significantly affecting those sales and services. 

Commission staff monitors the energy markets to ensure that the markets are 

functioning efficiently and appropriately. This is done by monitoring market results 

and conditions and identifying anomalies. When the available data does not explain 

the anomalies, staff examines the matter and, if legitimate reasons are not found, 

investigations are initiated to determine if fraud or manipulation has occurred. 

The Commission also requires each RTO or ISO to have an independent market 

monitor. The market monitors can review all market activities in real-time. They 

also evaluate market rules and recommend changes, review and report on the performance of these markets, and must refer to the Commission any potential violations of the Commission’s rules, regulations or orders. 

The Energy Policy Act of 2005 gave the Commission the authority to assess substantial penalties (a million dollars a day per violation) for fraud and market manipulation, including manipulation of RTO and ISO markets. This authority will greatly help the Commission deter and penalize the types of abuses we found during the 
7 

California energy crisis several years earlier. The Commission has initiated several 

proceedings based on this authority, which applies to participants in RTO and ISO 

markets as well as any other entity engaging in fraud or market manipulation in 

connection with a FERC-jurisdictional transaction. 

FERC’s efforts on market oversight and enforcement have increased greatly in recent years. Ten years ago, FERC investigatory staff consisted of 14 attorneys and 

a few support personnel within its Office of General Counsel. Today, staff in FERC’s 

Office of Enforcement (including market oversight, investigations and audits) numbers over 180, including 40 attorneys in its Division of Investigations. For fiscal year 

2009, FERC’s efforts yielded settlements worth approximately $38 million in penalties and $38 million in disgorgement. Six of those matters involved market manipulation claims and accounted for approximately $20.8 million in penalties and $28.8 

million in disgorgement. A complete list of such actions for 2007-2009 is appended 

as Attachment A to my testimony. 

The Commission’s transparency requirements are also quite extensive. For example, every public utility (whether within or outside of an RTO or ISO) must file a 

quarterly report listing every wholesale sale it made during the preceding quarter. 

The RTOs and ISOs also have substantial reporting requirements for bids and 

transactions in their markets. 

FINANCIAL TRANSMISSION RIGHTS

The question of CFTC regulation of energy markets has arisen in several contexts. 

Examples include RTO/ISO markets for financial transmission rights (FTRs), capacity markets and day-ahead markets. Another example is the question of whether 

RTOs/ISOs should be considered ‘‘clearing’’ organizations within CFTC jurisdiction. 

I will focus here on FTRs, as an illustration of the possible effects of CFTC regulation in these areas. 

FTRs allow customers to protect against the risk of price increases for transmission services in RTOs/ISOs. An FTR is a right to lock in congestion costs between two specific points. For example, if the transmission capacity going from 

Point A to Point B is 500 MW, but the RTO or ISO seeks to send 600 MW of power 

from Point A to Point B when calling on the least-cost generators to serve load, the 

path will be congested, and the price of service will increase because a more expensive generator at Point B will need to be dispatched. The increase is referred to as 

congestion costs. 

In general, load-serving entities in RTOs/ISOs are allocated either FTRs or rights 

convertible into FTRs. The allocation is generally based on usage during a historical 

period, as modified in certain circumstances for later changes. While allocated FTRs 

are generally limited to load-serving entities and to those who funded construction 

of specific transmission facilities, other FTRs are auctioned and these generally can 

be purchased by any creditworthy entity. 

Historically, FTRs were developed to give load-serving entities price certainty 

similar to the pricing methods in non-RTO/ISO markets. In most cases, FTRs have 

terms of one year or less. In the Energy Policy Act of 2005, however, Congress enacted Federal Power Act section 217, requiring FERC to use its authority in a way 

that enables load-serving entities to secure FTRs on a long-term basis for long-term 

power supply arrangements made to meet their customer needs. 

Unlike ‘‘futures contracts,’’ FTRs are available only to the extent allowed by the 

physical limits of the grid. All of the FTRs must be ‘‘simultaneously feasible’’ on the 

grid. Financial derivatives, by contrast, are not limited by physical capacities and 

instead are limited only by the willingness of market participants to take an opposite ‘‘bet.’’ 

Also, markets for FTRs include hundreds or thousands of different FTRs (for each 

pairing of receipt and delivery points) and thus are much more fragmented and less 

liquid than typical contracts of fungible commodities traded on futures exchanges. 

(Attachment B to my testimony provides statistics on this point.) Since an FTR applies to a specific pair of receipt and delivery points, it is not fungible with an FTR 

for a different pair of points. 

FTR markets do not pose systemic risk to the economy. All FTR markets combined amount to roughly several billion dollars. This market level fluctuates depending on the level of physical congestion in each RTO and is expected to decrease substantially as more transmission is built relieving congestion. 

THE COMMODITY EXCHANGE ACT AND PROPOSED LEGISLATION

Questions have been raised about whether FERC-regulated energy markets, including FTRs or other products, fall within CFTC jurisdiction under the Commodity 
8 

Exchange Act. Similar questions arise under proposed bills on financial derivatives, 

such as H.R. 4173. 

For example, some may argue that an FTR is a solely financial arrangement and 

constitutes a futures contract under the Commodity Exchange Act, or that an RTO 

or ISO is a ‘‘derivatives clearing organization’’ under that Act. Either of these arguments, if accepted, may establish CFTC jurisdiction. 

Moreover, my understanding is that the CFTC construes its jurisdiction under the 

Commodity Exchange Act to be exclusive. If so, the issue could become, not whether 

to allow dual regulation by FERC and the CFTC, but whether FERC regulation will 

be ended and replaced by CFTC regulation, even though the CFTC has neither the 

authority nor the expertise to ensure the reasonableness of price levels or oversee 

reliability of energy supplies. 

Under proposed legislation, some may argue that FTRs or other FERC-regulated 

agreements fit within the definition of a ‘‘swap.’’ For example, they may argue that 

the definition of ‘‘swaps’’ in proposed legislation includes capacity contracts (giving 

a customer in an RTO/ISO or bilateral market the right to buy electricity from a 

generating facility or other resources). This argument, however, ignores the fact that 

capacity contracts are critically important in ensuring the reliability of future electricity supplies, i.e., that there is enough ‘‘steel in the ground’’ and other resources 

to meet those needs. Thus, these agreements may be subjected to a regulatory 

scheme crafted for circumstances entirely unrelated to, and arguably ill-suited for, 

the energy markets. 

CONGRESS SHOULD PRESERVE FERC REGULATION OF ENERGY MARKETS

In addition to offering FTRs, certain RTOs and ISOs operate day-ahead and realtime energy markets, capacity markets and ancillary service markets. The rules for 

determining the prices for various power sales and transmission services—including 

congestion costs—are inextricably intertwined in the tariffs and in software as an 

integrated market design. This integrated design under comprehensive FERC oversight differs significantly from the way in which many other derivatives markets 

evolved, where the derivatives developed independently from the markets for their 

underlying commodities. 

All elements of these markets are approved by FERC, incorporated into FERCapproved tariffs, and monitored closely by the independent market monitors and 

FERC. Subjecting one or more of these to CFTC regulation could disrupt the integrated functioning of RTO/ISO markets, leading to market inefficiencies and higher 

energy costs for consumers. 

For example, as noted above, load serving entities generally are allocated FTRs 

as a means to hedge the transmission costs they incur and, ultimately, recover from 

their customers. CFTC requirements on position limits could conceivably require different allocations than the tariff rules approved by FERC. A utility currently allocated, e.g., half of the FTRs on a transmission path it has used and funded for many 

years could find its allocation reduced significantly, and find itself unhedged against 

congestion costs. 

Similarly, subjecting FTRs to CFTC clearing rules could conflict with FERC-approved tariff provisions on creditworthiness. FERC-approved tariffs reflect a balance 

between limiting the risk of defaults and unduly increasing the costs incurred by 

market participants and, ultimately, consumers. FERC also recognizes that different 

approaches to credit may be warranted for different types of power market participants (such as municipal utilities, cooperative utilities and federal agencies), unlike 

the one-size-fits-all approach that may suit other markets. There is no reason to assume that policies crafted by the CFTC in a different regulatory context apply 

equally well here. 

Any changes that may be warranted in FERC-regulated markets can be made by 

FERC and do not necessitate a shift of authority to another agency. For example, 

two months ago FERC proposed to require several actions to strengthen credit rules 

in the RTO and ISO markets. The proposed actions include reducing or eliminating 

the use of unsecured credit in those markets, and shortening the time allowed for 

posting of additional collateral. In a separate action, the Commission asked for comments on whether to require comprehensive reporting of resales of FTRs in secondary markets. I have also asked FERC staff to begin conducting outreach with 

market participants on the idea of position limits for FTRs and other energy markets. FERC is open to exploring other issues as appropriate, including whether financial participants in energy markets can create systemic risk and the usefulness 

of ‘‘secondary markets’’ for resale of FERC-regulated products and services. 

Congress has recognized FERC’s role in ensuring that FTRs help protect utilities 

and their customers from increases in the cost of transmission service. As noted 
9 

above, Congress in 2005 enacted Federal Power Act section 217, requiring FERC to 

use its authority in a way that enables load-serving entities to secure FTRs on a 

long-term basis for long-term power supply arrangements made to meet their customer needs. 

Moreover, Congress has indicated that RTOs and ISOs should be regulated exclusively by FERC. When Congress enacted the Food, Conservation, and Energy Act 

of 2008 and addressed the regulatory gap known as the ‘‘Enron loophole,’’ by giving 

the CFTC authority over ‘‘significant price discovery contracts [SPDCs],’’ the Conference Report stated (on page 986) that ‘‘[i]t is the Managers’ intent that this provision [on SPDCs] not affect FERC authority over the activities of regional transmission organizations or independent system operators because such activities are 

not conducted in reliance on section 2(h)(3) [of the Commodity Exchange Act].’’ In 

a colloquy with Senator Bingaman, Senator Levin emphasized this point, stating 

that ‘‘it is certainly my intention, as one of the amendment’s authors—that FERC’s 

authority over RTOs would be unaffected.’’ Cong. Rec., Dec. 13, 2007, S15447. More 

recently, the House of Representatives passed H.R. 2454, the American Clean Energy and Security Act of 2009, which (in section 351) would amend the Commodity 

Exchange Act to define ‘‘energy commodity’’ as including ‘‘electricity (excluding financial transmission rights which are subject to regulation and oversight by the 

Federal Energy Regulatory Commission.)’’ 

Congress has taken care to avoid duplicative regulation elsewhere in the electric 

industry. For example, the Federal Power Act exempts state agencies from regulation as public utilities; preserves State authority over local distribution and intrastate commerce (including much of Texas); and exempts cooperatives from regulation as public utilities if they are financed by the Rural Utilities Service. The same 

approach of avoiding duplicative regulation is warranted here. 

State regulators support FERC’s jurisdiction in wholesale energy markets instead 

of a shift of jurisdiction to the CFTC. Last month, the National Association of Regulatory Utility Commissioners (NARUC) adopted a resolution stating that FERC 

(and, within ERCOT, the state commission) ‘‘should continue to be the exclusive 

Federal regulator with authority to oversee any agreement, contract, transaction, 

product, market mechanism or service offered or provided pursuant to a tariff or 

rate schedule filed and accepted by the FERC. . . .’’ 

The impetus for legislation on financial derivatives is the financial turmoil caused 

by certain unregulated financial derivatives and other factors. As Chairman Gensler 

stated in recent testimony before the House Committee on Agriculture: ‘‘One year 

ago, the financial system failed the American public. The financial regulatory system failed the American public.’’ He also stated that ‘‘[w]e now face a new set of 

challenges as the nation continues to recover from last year’s failure of the financial 

system and the financial regulatory system.’’ The FERC-regulated energy markets 

did not cause these problems. Any response by Congress should address the source 

of these problems, and not inadvertently sweep in the FERC-regulated markets, 

since these have continued to perform well. 

In short, FERC has many years of experience with the energy markets. While I 

and others continue to seek improvements in these markets, I see no problem in 

these markets that would be solved by supplementing or displacing FERC oversight 

with CFTC oversight. No regulatory failure has occurred that would warrant such 

a major shift in oversight of these markets. These markets are vital in meeting the 

energy needs of many millions of Americans, and nothing has been proffered to warrant the uncertainty of inserting a new regulator and a new regulatory regime. 

The potential harm that would ensue, however, if the regulation of the energy 

markets was taken from FERC could be substantial. Investment in infrastructure 

needed both to maintain reliability and to develop clean renewable energy resources 

could be impeded. Consumer protection could be impaired and the benefits to consumers from viable competitive energy markets could be compromised. In sum, the 

current system of FERC oversight and comprehensive regulation of electric and gas 

markets is working well. Changing that system will not enhance benefits to consumers, but only put them in jeopardy. 

CONCLUSION

Late last year, Chairman Gensler testified that giving the Federal Reserve certain 

authority in financial markets ‘‘has the potential of setting up multiple regulators 

overseeing markets and market functions in the United States.’’ He also stated that 

‘‘[w]hile it is important to enhance the oversight of markets by both the SEC and 

CFTC, I think Congress would want to closely consider whether it’s best to set up 

multiple regulators for some functions.’’ The context of today’s hearing is different, 

but the concern is the same. Any improvements warranted in FERC-regulated mar-
10 

kets can be made by FERC. Interposing a new regulator, or having multiple regulators, has not been justified, is not needed and would be harmful. 
11 
12 
13 
14 

The CHAIRMAN. Thank you very much. 

Chairman Gensler, go right ahead. 

STATEMENT OF GARY GENSLER, CHAIRMAN, COMMODITY 

FUTURES TRADING COMMISSION 

Mr. GENSLER. Thank you, Chairman Bingaman, Ranking Member Murkowski, and Senator Corker. It is an honor to be here today 

and testify on behalf of the full commission, the CFTC. 

Before I just turn to OTC derivatives reform, let me just say one 

moment about what the CFTC is because I do not often come before this committee. We regulate exchanges, clearinghouses, other 

intermediaries to ensure—and I think Jon captured this—to make 

sure the markets work efficiently, there is integrity to markets, 

and they are free of fraud, manipulation, and of course, that we are 

promoting transparency, which is so important to the public markets. That helps lower risk to the full American public. 

We, of course, also have broad surveillance and enforcement authority and are sort of a cop on the beat. 

When Congress first brought regulation to the futures markets, 

which were derivatives markets that existed since the Civil War, 

they brought that regulation in the 1920s and 1930s. They sought 

to ensure uniformity across the then-derivatives markets which we 

called futures, and the CFTC was later formed out of the Agriculture Department in the 1970s overseeing the futures trading not 

only in the original grain products but also in oil and natural gas, 

gasoline, electricity, and so forth. 

So the CFTC overseeing these derivative markets, coexists and 

routinely cooperates with other agencies. We coexist, for instance, 

with the Department of Agriculture that helps set milk prices 

throughout the country, and we do coexist, I think very well, with 
15 

FERC, and as the chairman mentioned under the Energy Policy 

Act of 2005, for example, this committee working across parties 

and with the House set up new manipulation standards for FERC, 

and we have worked jointly with them. I think those authorities 

that were in EPAct are very important to help protect the markets 

that FERC oversees. 

But at the same time, the CFTC does oversee the futures markets in electricity and natural gas, whether they trade in NYMEX 

or the Nodal Exchange or this new Intercontinental Exchange. 

In a well functioning market, derivatives help to mitigate and 

lower risk, and of course, the financial crisis dramatically showed 

how the unregulated over-the-counter marketplace instead could 

heighten risk and concentrate risk. So working together with Congress—and I see Senator Corker because I know you are at the 

center of this on another committee—working together, we are trying to regulate the over-the-counter derivatives market. There are 

3 essential pieces, if I might say. 

One is to regulate the dealers. These are the large swap dealers. 

Usually they are part of an institution too big to fail, but those 

swap dealers. 

Two is to bring transparency into the markets requiring transparent trading on trading platforms or even fully regulated exchanges, coupled with aggregate position limit authority. 

Three is to lower risk further to bring standard transactions to 

central clearing. 

Now, electricity derivatives are part of that. Natural gas derivatives may be part of that. Consistent with the way that the CFTC 

and the FERC coexist to date in the futures markets, I believe that 

both agencies should continue to coexist with each of their very important and respective missions. We have a strong relationship 

with the commission. We are working actually with the FERC right 

now. Jon and I have met and the staffs have met about the rule 

that he mentioned on lowering risk in the RTO markets. Ours is 

just to give advice. They are taking the lead, of course. 

But as Congress works through OTC derivatives reform, I think 

it should avoid wholesale statutory exemptions, exemptions that 

could lead to the CFTC regulation of futures contracts, swaps contracts, clearing or exchanges to be exempt in a certain or particular 

market. We actually have some history with exemptions, and any 

such statutory exemptions can undercut the goal of comprehensive 

reform and weaken market protection. It is particularly hard to 

craft such exemptions, bright line exemptions, as the chairman 

mentioned, and consistent with the public interest because markets 

evolve, products evolve. 

History demonstrates that such bright line exemptions can lead 

to their own unintended consequences. What seems to be well 

crafted, carefully crafted later becomes a significant loophole. You 

know, when the Enron loophole was included in statute in 2000, 

electronic trading facilities were at their infancy, but as these electronic facilities went on, and by the time it was addressed in 2008 

in the Farm Bill, we had to bring in unregulated markets that 

were actually larger than the original regulated markets. 

So I think the proponents of exemptions have argued and they 

are concerned about additional CFTC regulation and they think it 
16 

is unnecessary. I think that our 2 agencies can work well together. 

We have to date. We coexist with many other agencies. 

So I thank you for having me here. I understand you are on a 

tight schedule. So I look forward to any questions as they come up. 

[The prepared statement of Mr. Gensler follows:] 

PREPARED STATEMENT OF GARY GENSLER, CHAIRMAN, COMMODITY FUTURES TRADING

COMMISSION

Good afternoon Chairman Bingaman, Ranking Member Murkowski and members 

of the Committee. Thank you for inviting me to testify regarding the regulation of 

over-the-counter (OTC) derivatives, particularly with respect to energy markets. I 

am pleased to testify on behalf of the Commodity Futures Trading Commission. 

The 2008 financial crisis left us with many lessons and many challenges to tackle. 

Though there were certainly many causes of the crisis, I think most would agree 

that the unregulated OTC derivatives marketplace played a central role. We must 

now bring comprehensive regulatory reform to the OTC marketplace for derivatives. 

CFTC REGULATORY REGIME

Before I discuss the details of much-needed OTC derivatives reform, let me take 

a moment to discuss the Commodity Futures Trading Commission’s (CFTC) current 

oversight of particular derivatives markets, called futures markets. Futures have 

traded since the Civil War, when grain merchants came together to hedge the risk 

of changes in the price of corn, wheat and other grains on a central exchange. It 

took nearly 60 years until Congress first brought Federal regulation to the futures 

markets. President Roosevelt and Congress further responded to our last great financial crisis by strengthening regulation and oversight of the commodities and futures markets through the Commodity Exchange Act (CEA), which created the 

CFTC’s predecessor within the Agriculture Department. 

The CFTC ensures that futures and commodity options exchanges protect market 

participants and promote fair and orderly trading, free from fraud, manipulation 

and other abuses. Exchanges are where buyers and sellers meet and enter into 

transactions. The CFTC also oversees clearinghouses, which enter the picture only 

after two counterparties complete a transaction. Clearinghouses act as middlemen 

between and guarantee the obligations of the two parties to the trade and take on 

the risk that one party may fail to meet its obligations for the duration of the contract. Centralized clearing has helped lower risk to the markets for more than a century, in both calm markets and in the stormiest of markets, such as during the 2008 

financial crisis. 

In addition to regulating exchanges and clearinghouses, the CFTC regulates market participants, including futures commission merchants, commodity trading advisors and commodity pool operators. The CFTC has wide-ranging transparency efforts designed to provide the public much information about commodity futures markets and trading. The agency also has broad surveillance and enforcement powers 

to police the markets for fraud, manipulation and other abuses. 

CFTC COORDINATION WITH OTHER AGENCIES

While many different federal agencies oversee various cash markets throughout 

the economy, Congress determined that the CFTC should be the sole agency to oversee trading on futures exchanges. One of the principal reasons that Congress mandated this exclusive jurisdiction was to bring uniformity to the regulation of the regulated derivatives markets. Importantly, the CFTC also was given the authority to 

provide exemptions from regulatory requirements for specific instruments or markets where it is in the public interest to do so. 

Though the CFTC has exclusive jurisdiction over the futures markets, it coexists 

and routinely cooperates with other agencies that have jurisdiction over cash markets for the underlying commodities. The Department of Agriculture, for example, 

regulates marketing standards for corn and cash milk prices, while the CFTC regulates corn and milk futures. The Grain Inspection, Packers and Stockyards Administration oversees spot livestock markets, while the CFTC regulates livestock futures. 

The Treasury Department oversees the issuance of all Treasury Bills, Notes and 

Bonds, while the CFTC oversees futures contracts based on those instruments. The 

Federal Reserve Board oversees interest rate levels, while the CFTC oversees interest rate futures. The Federal Energy Regulatory Commission (FERC) oversees important aspects of the energy markets, including monitoring natural gas pipelines 

and regulating for just and reasonable wholesale electricity rates and interstate 
17 

transmission service of electricity, while the CFTC oversees futures markets and 

certain electronic trading facilities for natural gas and electricity derivatives. 

REGULATION OF ENERGY FUTURES MARKETS

A transparent and consistent playing field for all physical commodity futures— 

from agricultural products, such as corn and wheat, to energy products, such as 

crude oil and natural gas—should be the foundation of our regulations. In the energy markets, the CFTC currently oversees the trading of futures and options on 

futures on crude oil, heating oil, natural gas, gasoline and electricity, among others, 

traded on designated contract markets, such as the New York Mercantile Exchange 

(NYMEX), and on an exempt commercial market—the Intercontinental Exchange 

(ICE). 

Vibrant energy futures markets are vital to the American economy. In 2009, more 

than 377 million energy futures and options contracts were traded on CFTC-regulated exchanges. The highest volume crude oil futures market was NYMEX’s West 

Texas Intermediate crude oil contract with 137 million contracts. That is the equivalent of 137 billion barrels of oil—equal to the United States usage for about 11 

years—with a notional value of nearly $9 trillion. The largest contract in natural 

gas was NYMEX’s Henry Hub contract with 48 million contracts. That is the equivalent of 480 billion mmBTU’s of natural gas with a notional value of $2.17 trillion. 

Energy futures and options markets also include very significant trading in electricity contracts, which, as a class, had more than 26.4 million contracts traded representing 7% of the overall futures and options trading volume in the energy sector. 

Congress has continued to reaffirm the CFTC’s role in regulating futures markets. 

In the 2008 Farm Bill, Congress broadened the CFTC’s authority to regulate derivatives, including energy derivatives, traded on previously-exempted electronic trading 

facilities, called exempt commercial markets (ECMs). If a contract that is traded on 

one of these facilities is found to perform a significant price discovery (SPDC) function, the trading of that contract on that facility is subject to heightened regulation 

and required to comply with key core principles that also apply to the trading of 

futures contracts. 

The Commission has so far determined that the ICE Henry Financial LD1 Fixed 

Price Contract traded on the ICE—the largest volume natural gas swap contract 

traded on an ECM—serves a significant price discovery function, and thus subject 

to heightened regulation. Following the statutory obligations of the 2008 Farm Bill, 

the CFTC is analyzing—and has sought public comment on—an additional 42 energy contracts, including natural gas and electricity contracts, to determine whether 

they meet the criteria to be regulated as SPDCs. 

OTC DERIVATIVES REGULATION

Nearly 60 years after the futures markets were regulated, the first OTC swap was 

transacted in 1981. During its early years, the OTC marketplace was highly tailored 

to meet specific risk management needs. Contracts were negotiated between dealers 

and their corporate customers seeking to hedge specific financial risks. In contrast 

to the regulated futures markets, these early OTC derivatives were not traded on 

exchanges. Instead, OTC derivatives were transacted bilaterally, with dealers standing between their various customers. In this market structure, dealers keep transactions on their books, leaving the financial institutions more interconnected with 

all of their customers and limiting the amount of relevant pricing information available to the public. 

In the last three decades, the over-the-counter derivatives marketplace has grown 

up, but it remains largely unregulated. Since the 1980s, the notional value of the 

market has ballooned from less than $1 trillion to approximately $300 trillion in the 

United States—that’s $20 in derivatives for every dollar of goods and services produced in the American economy. The contracts have become much more standardized, and rapid advances in technology—particularly in the last ten years—now can 

facilitate transparent trading of much of this market on electronic platforms. While 

so much of this marketplace has changed significantly, the constant that remains 

is that it is largely unregulated and still dealer dominated. 

It is now time to bring comprehensive regulation to this large and economically 

significant market. In well functioning markets, derivatives are meant to mitigate 

and help manage risk in the economy. Even if not for the 2008 financial crisis, this 

market should be regulated to achieve these goals. The financial crisis only highlights this in dramatically revealing how unregulated OTC derivatives and their 

dealers actually can heighten and concentrate risk to the great detriment of the 

American public. The need for broad based reform is the ultimate lesson of AIG and 

the broader risks brought about by the unregulated OTC derivatives market. 
18 

Effective reform requires many pieces. I will focus on the three essential components that should be enacted to promote transparency and reduce risk to the American public. 

First, we must establish an explicit regulatory framework for swap dealers and 

major swap participants. 

Second, we must bring transparency to these markets by requiring that standardized derivatives be traded on regulated trading platforms. 

Third, we must lower the risk to the American public of financial institutions that 

have become both ‘‘too big to fail’’ and ‘‘too interconnected to fail’’ by requiring that 

their standardized derivatives be brought to central clearinghouses. 

Regulating the Dealers 

There is now broad consensus that dealers should be regulated for all of their derivatives business, both customized transactions and standardized ones. Swap dealers and major swap participants should maintain sufficient capital and meet margin 

requirements on their swap businesses to lower risk to the American public. They 

should be required to meet business conduct standards to a) promote market integrity by protecting against fraud, manipulation and other abuses and to b) lower risk 

through uniform back office standards for netting, processing and documentation. 

This should include authority for regulators to set aggregate position limits for OTC 

derivatives contracts when they perform or affect a significant price discovery function with respect to regulated markets. Swap dealers and major swap participants 

also should meet recordkeeping and reporting requirements promoting transparency 

to the regulators. 

Transparent Trading Requirement 

It is not enough, though, simply to promote transparency to the regulators. Financial reform will be incomplete if we do not make the OTC derivatives marketplace 

transparent to the public. 

The majority of the OTC market, by some estimates more than three quarters of 

the market, could be cleared by a clearinghouse. Customized contracts—those that 

are so tailored that they cannot be cleared by a clearinghouse or listed on a trading 

platform—should be allowed to be transacted bilaterally, with the dealers subject 

to comprehensive regulation for these transactions. 

This leaves the important public policy question of whether to require standardized OTC transactions to be brought to transparent, regulated, trading platforms. 

An opaque derivatives market, concentrated amongst a small number of financial 

institutions, though, contributed to bringing our financial system to the brink of collapse. Public market transparency greatly improves the functioning of existing securities and futures markets. We should shine the same light on the OTC derivatives 

markets. The more transparent a marketplace, the more liquid it is. 

The more transparent a marketplace, the more competitive it is. And the more 

transparent a marketplace, the lower the costs for hedgers, borrowers and, ultimately, their customers. The best way to bring transparency is through regulated 

trading facilities and exchanges—including establishing a mechanism to provide for 

the timely public reporting of key trading data. Such centralized trading venues not 

only bring greater transparency, but increase competition in the markets by encouraging market-making and the provision of liquidity by a greater number of participants. A greater number of market makers brings better pricing and lowers risk to 

the system. 

Further, clearinghouses would be far more able to assess and mange the risk of 

OTC derivatives with the benefit of transparent trading markets. A critical element 

of managing clearinghouse risk is marking all cleared positions to a reliable and 

transparent market price. 

Absent the transparency provided by trading venues, clearinghouses have less reliable prices when marking to market the derivatives they clear and, thus, are less 

able to manage their risk and protect the public. 

Some on Wall Street have suggested that they could support a clearing requirement, but see no need for a transparency requirement. But make no mistake: transparency is an absolutely essential component of reform. Congress should require 

that all standardized OTC derivative transactions be moved onto regulated transparent exchanges or trade execution facilities. 

Mandating Clearing of Standardized Derivatives 

Congress also should require derivatives dealers to bring their completed standardized derivatives transactions to regulated clearinghouses. 

Currently, OTC derivatives transactions stay on the books of the dealers, often 

for many years after they are arranged. These dealers engage in many other businesses, such as lending, underwriting, asset management, securities trading and de-
19 

posit-taking. When there is a better alternative through central clearing, why leave 

these derivatives transactions on the books of the swap dealers when these institutions are possibly ‘‘too big to fail?’’ Bilateral derivatives also leave a financial institution possibly ‘‘too interconnected to fail.’’ Leaving standardized OTC derivatives 

transactions on the books of the banks further aggravates the Governments’ dilemma when faced with a failing institution. Central clearing would greatly reduce 

both the size of dealers as well as the interconnectedness between Wall Street 

banks, their customers and the economy. 

Some corporations have expressed concerns regarding posting the collateral required to clear a contract. While this is a legitimate public policy debate, I believe 

that the public is best served by lowering risk to the system as a whole. An exemption from clearing for this large class of transactions would allow dealers to keep 

significant risk on their books—risk that could reverberate throughout the entire financial system if a bank fails. Further, it is not clear that posting collateral necessarily increases costs to end users, since dealers charge corporations for credit extensions when the corporations do not post margin. 

If Congress ultimately determines that commercial end-users’ transactions should 

be exempt from a clearing requirement, the exemptions should be narrow. Data 

from the Bank for International Settlements shows that dealer-to-dealer transactions comprise 40 percent or less of the market in most contracts. Contracts with 

financial firms make up the bulk of transactions with non-dealers. For instance, 

swaps with non-dealer financial firms make up 57 percent of the interest rate derivatives markets. Exempting transactions with non-dealer financial firms exposes 

the American public to great risk by leaving the broader financial system significantly interconnected through their standard derivatives transactions. At a minimum, legislation should mandate that trades between dealers and other financial 

firms be cleared on regulated clearinghouses. Hedge funds, for example, should not 

be exempt from a clearing requirement with respect to their OTC transactions. 

Further, any commercial end-user exception from clearing should not bring along 

an exemption from a transparency requirement. Commercial end-users have raised 

concerns about posting margin if they are required to clear their transactions. Separating the trading requirement from the clearing requirement can address this concern, if need be. Indeed, most commercial end-users would benefit from greater 

transparency than Wall Street currently provides. 

REGULATION OF ELECTRICITY DERIVATIVES

As we move to bring comprehensive reform to the OTC derivatives marketplace, 

the new authorities granted to market regulators will necessarily relate to existing 

authorities of other federal regulators. Specifically, CFTC authorities for OTC energy derivatives would relate to the FERC’s authority under the Natural Gas Act 

and the Federal Power Act, including the authority to regulate certain activities of 

Regional Transmission Organizations (RTOs) and Independent System Operators 

(ISOs). Consistent with the CFTC’s and FERC’s currently co-existing regulatory authorities, both agencies should continue to apply their authorities to the activities 

that are within their respective jurisdictions. 

The CFTC has exclusive jurisdiction over the trading and clearing of futures contracts, whereas the FERC has jurisdiction over other defined aspects of the energy 

markets, including regulating interstate transportation rates and services for natural gas pipelines and regulating wholesale sales of electricity and interstate transmission rates and services. The FERC also has important enforcement authorities 

under the Federal Power Act and the Natural Gas Act to prosecute manipulation 

in the electricity and natural gas markets. Contracts for the immediate or forward 

delivery of electricity—like all cash and forward contracts for other commodities— 

are not regulated by the CFTC. 

Congress has provided the agencies with adequate tools to work cooperatively. 

The CEA provides the CFTC with authority to exempt instruments and markets 

from its regulations if it is determined to be in the public interest to do so. OTC 

derivatives reform should extend this exemptive authority with the CFTC’s oversight of the swaps market. Any potential overlaps in oversight can be addressed 

through memoranda of understanding and other cooperative working relationships 

between the two agencies. Pending legislation also should maintain the FERC’s enforcement authorities under Section 222 of the Federal Power Act and Section 4A 

of the Natural Gas Act. 

In contrast, wholesale statutory exemptions preventing the application of any 

CFTC regulation—including the regulation of futures contracts, swaps contracts, 

clearing or exchange trading—for any instrument or market that is regulated by the 

FERC undermine the effectiveness of comprehensive reform. Congress should avoid 
20 

any bright-line exemption that runs the risk of creating the next regulatory loophole. Instead, Congress should follow the long established model under which the 

CFTC coexists with other agencies with oversight of cash and forward markets. 

History demonstrates that bright-line statutory exemptions or exclusions granted 

at one point in time can have unintended consequences and often fail to adequately 

account for subsequent developments. Markets evolve rapidly. What may seem like 

a carefully crafted exclusion today can become a significant and problem-filled loophole tomorrow. When the Enron loophole was included in statute in 2000, electronic 

trading facilities were in their infancy. By the time Congress addressed the loophole 

as part of the Farm Bill in 2008, the unregulated electronic trading of natural gas 

swaps was on a par with the trading of natural gas futures on the regulated market. 

As the Amaranth case demonstrated, traders took advantage of the unregulated exempt facility to avoid position limits and other regulations established for the regulated futures markets. Proponents of the exemptions had argued that additional 

CFTC regulation was unnecessary. Our experience, though, indicates that comprehensive and consistent oversight must be applied. 

CLOSING

I thank you for inviting me to testify today. I look forward to working with you 

in the coming months to implement comprehensive reform of our financial regulatory system. I will be happy to answer any questions you may have. 

The CHAIRMAN. Thank you both for your excellent testimony. 

If we could just ask the 4 panelists in the second panel to come 

ahead and give their testimony, and then we will have some questions of all 6 witnesses. 

Let me introduce this second panel as they are coming forward. 

We have the Honorable Garry Brown, who is Chairman of the New 

York Public Service Commission and Chair of NARUC’s Committee 

on Electricity. We have Mr. Vincent Duane, who is with PJM Interconnection in Norristown, Pennsylvania. We have the Honorable 

Joseph Kelliher, representing Edison Electric Institute and The 

Electric Power Supply Association, and Mr. Michael Henderson, 

who is representing the Arkansas rural electric coops in Little 

Rock. 

Thank you all very much for being here. Why do we not start— 

let us see. I introduced you in the order of right to left, so why do 

we not just have you go ahead in that order, please. 

STATEMENT OF GARRY BROWN, CHAIRMAN, NEW YORK STATE 

PUBLIC SERVICE COMMISSION, ON BEHLAF OF THE NATIONAL ASSOCIATION OF REGULATORY UTILITY COMMISSIONERS 

Mr. BROWN. Good morning, Chairman Bingaman, Ranking Member Murkowski, and members of the committee. My name is Garry 

Brown. I am the Chair of the New York State Public Service Commission. I also serve as the Chair of the Electricity Committee on 

the National Association of Regulatory Utility Commissioners on 

whose behalf I am testifying here today. 

I am honored to have the opportunity to appear before you this 

morning and offer our perspectives on financial transmission rights 

and electricity market mechanisms. 

It is our understanding that some of the proposals being contemplated by Congress would provide the CFTC with oversight of 

OTC risk management products, including mandatory centralized 

clearing and exchange trading of all OTC products. NARUC believes that this approach could be detrimental to electricity and 

natural gas retail consumers. There is a diverse group of end users 

consisting of electric and natural gas utilities, suppliers, customers, 
21 

and other commercial entities who rely on OTC derivative products 

and markets to manage electricity and natural gas price risks for 

legitimate business purposes, thereby helping to keep commodity 

costs stable for retail consumers. In these situations, the mandatory centralized clearing of all OTC contracts as envisioned in proposed legislation will increase expenses associated with hedging activity and ultimately end-use prices due to increased margin requirements. 

State utility commissions regulate companies that rely on legitimate hedging activities and transaction in natural gas and electricity markets to keep commodity costs stable for retail customers. 

These companies use both exchange-traded and OTC derivatives to 

reduce their exposure to volatile spot markets which enables them 

to make sound medium-and long-term business decisions. A requirement for mandatory centralized clearing of all OTC contracts 

would increase the expenses associated with hedging activities and 

ultimately consumer prices due to increased margin requirements. 

Utilities would have to finance needed cash margins in the capital markets and pass these costs to customers through the ratemaking process or take other offsetting actions such as cutting 

back capital projects. Similarly, public utilities could lose access to 

long-term power supply contracts called pre-pays because the expense of ongoing cash margins would be prohibitive. We also understand that rural electric cooperatives could be forced to borrow 

large sums at unaffordable rates. In cases where these costs would 

prove to be too high, the energy supplier would need to reduce or 

cease hedging altogether, thus negatively impacting the ability to 

manage price volatility, resulting in higher costs to consumers. In 

short, consumers need the industry to have both cleared and OTC 

options available to provide price stability and lower costs. 

Additionally, the effect of margin requirements resulting from 

mandatory clearing for electric utilities could have the unintended 

consequence of reducing or eliminating legitimate hedging practices 

and jeopardizing or reducing investments in such things as Smart 

Grid technology and other infrastructure. 

We recognize the intent of the legislation is to minimize or eliminate manipulation in the OTC market, especially by speculators. 

One approach to address this concern is to have the mandatory requirements and a carefully crafted exemption from the requirements for legitimate utility transactions. 

Another concern that NARUC members have is the effect the 

various legislative proposals may have upon electric transmission 

entities. The proposed reforms, as we understand, would cause regulatory uncertainty with regard to the oversight of regional transmission organizations and independent system operators. This uncertainty and/or overlapping jurisdiction can lead to negative effects on liquidity, market confidence, and reliability. 

NARUC believes that the Federal Energy Regulatory Commission and, for the Texas/ERCOT region, the Public Utility Commission of Texas, as the regulators with the necessary expertise and 

statutory mandates to oversee wholesale electricity markets to protect the public interest and consumers. Energy markets currently 

regulated by FERC and PUCT under accepted tariffs or rate schedules should continue to be subject to their jurisdiction, including 
22 

over physical and financial transmission rights and market oversight, and should not be themselves subject to CFTC jurisdiction as 

a clearinghouse due to the financial and other settlement services 

they provide those transacting in regional electricity markets. 

In conclusion, NARUC supports passage of financial reform legislation ensuring that electric and natural gas markets continue to 

have access to OTC risk management products as a tool in their 

legitimate hedging practice to provide more predictable and less 

volatile energy costs to consumers, and would respectfully offer the 

following policy recommendations for inclusion in any financial reform legislation. 

The legislation should weigh the costs of potential end-user cost 

increases versus the benefits of new standards for the clearing of 

OTC risk management contracts. 

Any Federal legislation addressing OTC risk management products should provide for an exemption from mandatory clearing requirements for legitimate utility hedging activities. 

Any exemption to the mandatory clearing requirement for OTC 

derivatives should be narrowly tailored so as not to allow excessive 

speculation in natural gas and electricity markets. 

FERC should continue to be the exclusive regulator at the Federal level—and the PUCT for Texas/ERCOT—charged with the 

statutory obligation to protect the public interest and consumers, 

with authority to oversee any agreements, contracts, transactions, 

products, market mechanisms, or services offered or provided pursuant to a tariff or rate schedule. 

Thank you and I would be happy to answer questions later. 

[The prepared statement of Mr. Brown follows:] 

PREPARED STATEMENT OF GARRY BROWN, CHAIRMAN, NEW YORK STATE PUBLIC

SERVICE COMMISSION, ON BEHLAF OF THE NATIONAL ASSOCIATION OF REGULATORY

UTILITY COMMISSIONERS

Good morning Chairman Bingaman, Ranking Member Murkowski, and Members 

of the Committee: My name is Garry Brown, and I am Chairman of the New York 

State Public Service Commission (NY PSC). I also serve as Chair of the Electricity 

Committee of the National Association of Regulatory Utility Commissioners 

(NARUC), on whose behalf I am testifying here today. I am honored to have the 

opportunity to appear before you this morning and offer our perspective on financial 

transmission rights and electricity market mechanisms. 

NARUC is a quasi-governmental, non-profit organization founded in 1889. Our 

membership includes the public utility commissions serving all States and territories. NARUC’s mission is to serve the public interest by improving the quality and 

effectiveness of public utility regulation. Our members regulate the retail rates and 

services of electric, gas, water, and telephone utilities. We are obligated under the 

laws of our respective States to assure the establishment and maintenance of such 

utility services as may be required by the public convenience and necessity and to 

assure that such services are provided under rates and subject to terms and conditions of service that are just, reasonable and non-discriminatory. 

Congress is currently considering financial reform legislation with the goal of ensuring that gaps in regulation, oversight of markets and systemic risk do not lead 

to economic instability, but improve transparency and reduce systemic risk in the 

over-the-counter (OTC) derivatives markets. NARUC has consistently supported federal legislative and regulatory actions that fully accommodate legitimate hedging activities by electric and natural gas utilities; however, we are concerned that some 

legislative proposals could have adverse effects on the retail rates of electric and 

natural gas consumers. 

It is our understanding that some of the proposals being contemplated by Congress would provide the Commodity Futures Trading Commission (CFTC) with oversight of OTC risk management products, including mandatory centralized clearing 

and exchange trading of all OTC products. NARUC believes that this approach 
23 

could be detrimental to electricity and natural gas retail consumers. There is a diverse group of end-users, consisting of electric and natural gas utilities, suppliers, 

customers, and other commercial entities who rely on OTC derivative products and 

markets to manage electricity and natural gas price risks for legitimate business 

purposes, thereby helping to keep commodity costs stable for retail consumers. In 

these situations, the mandatory centralized clearing of all OTC contracts—as envisioned in proposed legislation—will increase expenses associated with hedging activity, and ultimately end-user prices, due to increased margin requirements. 

Electric and natural gas companies use derivatives to ‘‘hedge,’’ or lock in, the price 

of commodities they plan to buy or sell in the future. These companies use clearinghouses and exchanges (such as the New York Mercantile Exchange or NYMEX) 

when those markets provide the best deal. Often, however, OTC transactions— 

which are arranged company-tocompany or between a company and a bank—provide 

the lowest cost and/or the most stable pricing. In centralized clearing and exchange 

trading, the clearinghouse or exchange steps between buyers and sellers and guarantees payment by requesting a significant cash ‘‘margin’’ from both parties. These 

cash margins, a form of collateral, represent a portion of the value of each contract. 

For companies whose core businesses involve buying and selling energy commodities, cash margin requirements would translate into significant additional borrowing costs and/or reduced investment, which could require new borrowing at a 

time when business loans and other financing are both more expensive and harder 

to get. 

State utility commissions regulate companies that rely on legitimate hedging activities and transactions in natural gas and electricity markets to keep commodity 

costs stable for retail customers. These companies use both exchange-traded and 

OTC derivatives to reduce their exposure to volatile spot markets, which enables 

them to make sound medium-and long-term business decisions. A requirement for 

mandatory centralized clearing of all OTC contracts would increase the expenses associated with hedging activity, and ultimately consumer prices, due to increased 

margin requirements. 

Utilities would have to finance needed cash margins in the capital markets—and 

pass those costs to customers through the ratemaking process—or take other offsetting actions, such as cutting back capital projects. Similarly, public utilities could 

lose access to long-term electric power supply contracts called pre-pays because the 

expense of ongoing cash margins would be prohibitive. We also understand that 

rural electric cooperatives could be forced to borrow large sums at unaffordable 

rates. In cases where these costs would prove to be too high, the energy supplier 

would need to reduce or even cease hedging altogether, thus negatively impacting 

the ability to manage price volatility—resulting in higher costs to consumers. In 

short, consumers need the industry to have both cleared and OTC options available 

to provide price stability and lower costs. 

Additionally, the effect of margin requirements resulting from mandatory clearing 

for electric utilities could have the unintended consequence of reducing or eliminating legitimate hedging practices and jeopardizing or reducing investments in 

Smart Grid technology and other infrastructure; similarly, natural gas utilities and 

production companies could reduce capital devoted to infrastructure and natural gas 

exploration. 

We believe that the laudable goals of reform that ensure market transparency and 

adequate regulatory oversight can be accomplished by means other than mandatory 

clearing of OTC risk management contracts and the anticipated extra expense. For 

example, a requirement that natural gas and electric market participants engaging 

in legitimate hedging report all OTC derivative transactions to a centralized data 

repository, like the CFTC, would provide sufficient market transparency without the 

costs associated with mandatory clearing. 

We recognize the intent of the legislation to minimize or eliminate manipulation 

in the OTC market, especially by speculators. One approach to address this concern 

is to have the mandatory requirements and a carefully crafted exemption from the 

requirements for legitimate utility transactions. 

Another concern that NARUC members have is the effects the various legislative 

proposals may have upon electric transmission entities. The proposed reforms, as we 

understand, would cause regulatory uncertainty with regard to the oversight of Regional Transmission Organizations (RTOs) and Independent System Operators 

(ISOs). This uncertainty and/or overlapping jurisdiction can lead to negative impacts 

on liquidity, market confidence and reliability. 

NARUC believes the Federal Energy Regulatory Commission (FERC) and, for the 

Texas/ERCOT region, the Public Utility Commission of Texas (PUCT), as the regulators with the necessary expertise and statutory mandates to oversee wholesale 

electricity markets to protect the public interest and consumers, should not be pre-
24 

empted by financial reform legislation from being able to continue exercising their 

authority to protect consumers and ensure reliable, just and reasonable service. Energy markets currently regulated by FERC and the PUCT under accepted tariffs or 

rate schedules should continue to be subject to FERC or PUCT jurisdiction, including over physical and financial transmission rights and market oversight, and 

should not themselves be subject to CFTC jurisdiction as a clearinghouse due to the 

financial and other settlement services they provide those transacting in regional 

electricity markets. 

In conclusion, NARUC supports passage of financial reform legislation ensuring 

that electric and natural gas market participants continue to have access to OTCrisk management products as tools in their legitimate hedging practices to provide 

more predictable and less volatile energy costs to consumers, and would respectfully 

offer the following policy recommendations for inclusion in any financial reform legislation: 

• The legislation should weigh the costs of potential end-user utility cost increases versus the benefits of new standards for the clearing of OTC-risk management contracts used by natural gas and electric utilities for legitimate hedging purposes. 

• Any federal legislation addressing OTC-risk management products should provide for an exemption from mandatory clearing requirements for legitimate utility hedging activity in natural gas and electricity markets. 

• Any exemption to the mandatory clearing requirement for OTC derivatives 

should be narrowly tailored so as not to allow excessive speculation in natural 

gas and electricity markets. 

• FERC should continue to be the exclusive regulator at the Federal level—and 

the PUCT for Texas/ERCOT—charged with the statutory obligation to protect 

the public interest and consumers, with authority to oversee any agreement, 

contract, transaction, product, market mechanism or service offered or provided 

pursuant to a tariff or rate schedule filed and accepted by the FERC, or the 

PUCT for Texas/ERCOT. 

Thank you and I would be happy to answer any questions. 

The CHAIRMAN. Thank you very much. 

Mr. Duane, go right ahead. 

STATEMENT OF VINCENT P. DUANE, VICE PRESIDENT AND 

GENERAL COUNSEL, PJM INTERCONNECTION, L.L.C., NORRISTOWN, PA 

Mr. DUANE. Thank you. Good morning, Mr. Chairman, Ranking 

Member Murkowski, and members of the committee. I am delighted to be here. Thank you for the invitation. 

The focus of the jurisdictional debate between the CFTC and 

FERC, at least the live question that we are facing today, is focused on the organized wholesale electricity markets. These ISO/ 

RTO environments have been created as a product of FERC regulatory initiative. We are operators, grid operators, with the responsibility to keep the lights on, and we administer markets, but these 

are markets unlike any other. These are very heavily regulated 

markets, reduced to writing, and filed as tariffs before the FERC. 

So why have these environments attracted this attention? Concededly, there are certain products that you will see in these organized wholesale electricity markets that have financial elements to 

them. They are forward, and the environment itself is a centralized 

environment. So there are appearances in these ISO/RTO environments that look like exchanges and there are products that have 

attributes that look like derivatives that have been traditionally 

the focus of the CFTC. 

I am not here today to speak to some of the issues my industry 

colleagues will address in the OTC markets. I am not here to talk 

about mandatory clearing or end-use exemptions. I am here just on 
25 

the question of the ISO/RTO organized markets and the products 

and services they provide. I am here for PJM, but you will see an 

attached statement to my testimony that reflects the thoughts of 

the Midwest ISO in Carmel, Indiana; the Southwest Power Pool in 

Little Rock, Arkansas; the California ISO; and ERCOT in Austin, 

Texas. 

Speaking of the products, the focus is the FTR product. What 

needs to be understood here is that the FTR is the means by which 

we as a transmission provider discharge our obligation to provide 

firm transmission service under FERC’s open access regime. The 

full complement of FTRs, which is derived from the physical capability of the transmission system, is allocated to the transmission 

customers that pay for the transmission system. It is not decorative 

architecture. It is not a financially engineered product that we 

market, and we market to whomever wants to buy it at whatever 

volumes. Rather, it is integral to our function as a transmission 

service provider squarely under the Federal Power Act and the 

FERC jurisdiction. 

As far as some of the services, we clear and risk manage this 

FTR bilaterally not in a multilateral manner. As a result, the DCO, 

or the derivatives clearing organization, principles that you will 

find in the Commodity Exchange Act are just wholly unworkable 

for the functions we provide predominantly because the RTO is not 

engaged in what I would view as the hallmark of a clearinghouse 

organization, that being multilateral clearing. 

So what we are proposing is that there should be a bright line. 

There should be some clarity that reflects the existing architecture 

in these wholesale electricity markets and reserves the jurisdiction, 

as has been the case for the past 10 years, to the Federal Energy 

Regulatory Commission. If necessary, complementary clarity can be 

given to the CFTC, recognizing their primacy in the area of exchange environments, clearinghouse environments, and to the extent they have jurisdiction over the financial OTC products. I think 

that is a clarity that can be brought. 

I want to close on the question of investigation and enforcement. 

There has been much debate in this area. I do not think the issue 

is so much a question of competing or overlapping jurisdiction. I 

think it is one of coordination. Schemes can be put in place by unscrupulous market participants that are multidimensional that cut 

across interrelated markets and interrelated environments with 

different regulators providing oversight. 

What we should do in any legislation is in the interests of consumer protection and sound public policy, encourage interagency 

coordination in these areas, build on the cooperative models that 

are already in place between the FERC and the CFTC to encourage 

data sharing and other coordination in this area. 

With that, let me close and make myself available to questions. 

Thank you. 

[The prepared statement of Mr. Duane follows:] 

PREPARED STATEMENT OF VINCENT P. DUANE, VICE PRESIDENT AND GENERAL

COUNSEL, PJM INTERCONNECTION, L.L.C., NORRISTOWN, PA 

My name is Vincent Duane and I serve as the Vice President and General Counsel for PJM Interconnection, L.L.C. (‘‘PJM’’). PJM is a FERC-regulated Regional 

Transmission Organization (‘‘RTO’’) responsible for ensuring the reliable and non- 
26 

discriminatory planning and operation of the transmission grid and the fair and efficient administration of wholesale electric markets. PJM serves 51 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—an area representing approximately 19 percent of the nation’s Gross Domestic Product. 

Thank you Chairman Bingaman and the Committee for inviting PJM to address 

this important subject. We recognize this Committee’s key role in considering the 

impact of proposals to effect regulatory reform of our nation’s financial markets. 

Our country’s financial markets are both varied and complex. And while the innovation and evolving sophistication of our financial institutions should be encouraged 

generally in order to manage risk, spur investment and realize efficiencies, the need 

for increased supervision over the trading of certain products in certain environments can no longer be doubted. However, let’s keep our ‘‘eye on the ball’’ by recalling why and where we need regulatory reform. 

Consider those products related to the purchase, sale and transmission of electricity which are undertaken in fully transparent environments administered by the 

nation’s Regional Transmission Organizations (‘‘RTOs’’) and Independent System 

Operators (‘‘ISOs’’). The transacting of these products in these environments should 

not be seen as warranting either a new regulator or a new regulatory construct. 

This is so, quite simply because the RTO/ISO products and their environments are 

already subject to comprehensive and proactive regulation by the Federal Energy 

Regulatory Commission (‘‘FERC’’). 

With Congress’ help, much important work needs to be done by the Commodity 

Futures Trading Commission (‘‘CFTC’’) to increase oversight and control and restore 

to a sounder footing the trading of certain financial products, such as swaps, in certain environments, such as over-the-counter platforms. But to direct the CFTC 

through the passage of new legislation or enable the CFTC, under an expansive interpretation of the existing Commodity Exchange Act, to assert regulatory jurisdiction in an area already fully occupied by the FERC is wasteful and an unwelcome 

distraction from the important job of the day: reforming the oversight of those products and trading environments that are unduly opaque and presently are lightly or 

inadequately supervised. 

Although I am testifying solely on behalf of PJM, several of the other RTO/ISOs, 

including the California ISO (operating in California), the Southwest Power Pool 

(operating in all or parts of the states of Kansas, Nebraska, Arkansas, Missouri, 

Oklahoma, New Mexico, Texas, and Louisiana), ERCOT (operating in the state of 

Texas) and the Midwest ISO (operating in 13 states in the Midwest) have authorized PJM to represent their concurrence in the attached statement reflecting sentiments and concerns similar to those stated in my testimony on behalf of PJM. See 

Attachment A, ‘‘Joint Statement of Identified RTOs/ISOs’’. 

1. What Is PJM? 

PJM is a FERC-regulated 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 incorporates 

56,000 miles of transmission lines, 1,250 generating plants and 6,000 substations. 

PJM has 250 intertie points with adjacent systems in the Eastern Interconnection, 

which means that along with managing the PJM system, our operators manage the 

interface between PJM and seven adjacent electric systems. 

2. Overview of this Testimony 

My testimony today will address the following areas: 

• An overview of the extensive involvement of FERC in both the creation and 

oversight of RTO/ISOs; 

• A description of certain RTO/ISO forward markets which some contend are subject to oversight by the CFTC; 

• The extensive regulation of these RTO/ISO forward markets by FERC and the 

Congress’ authorization of these markets under FERC jurisdiction; 

• The incongruity of CFTC regulation if applied to direct how RTOs/ISOs establish their products or perform their services and the problems that would arise 

from inconsistent, or worse, conflicting regulation should the CFTC seek to 

apply existing Commodity Exchange Act provisions to these products or functions; and 

• A potential legislative path forward that symmetrically defines the exclusive 

functions belonging to each agency and similarly defines those areas where 

shared interests and jurisdiction are implicated and thus where inter-agency coordination is warranted. 
27 

* Map has been retained in committee files. 

1 As the majority of the Texas grid is wholly intrastate and not interconnected with the rest 

of the Eastern Interconnection, the Electric Reliability Council of Texas (ERCOT) operates as 

an ISO in the state of Texas. Other than for regulation of ERCOT’s compliance with national 

reliability standards, ERCOT is subject to the regulation of the Public Utility Commission of 

Texas rather than the FERC. 2 16 USC 824d § 205. 

3. An Overview of FERC Regulation of RTO/ISOs 

PJM is one of seven RTO/ISOs in the United States. Together these entities serve 

over two-thirds of the nation. The map* below depicts the respective operational 

areas for each of the RTOs. 

RTO/ISOs are a creature of FERC regulation and Congressional pronouncements. 

These independent electricity grid operators were established to fulfill Congressional 

policy by introducing competitive forces to liberalize the traditional monopolistic 

utility industry. The restructuring of the industry began with the Public Utility Regulatory Policies Act of 1978, which introduced nascent competition to the supply 

(generation) side of the industry. This legislation was followed by a succession of 

laws, including the Energy Policy Act of 1992, which began efforts to unlock the 

bulk delivery (transmission) side of the industry. From these beginnings emanated 

FERC’s landmark Orders No. 888 and No. 2000 in 1996 and 1999 respectively. 

These orders demonstrate FERC’s commitment to independent, ‘‘open access’’ operation of the power grid (not dissimilar from how air traffic controllers operate independently from individual airlines). FERC determined that RTO/ISOs were the best 

means to effectuate the open access provisions of the Energy Policy Act of 1992. 

While neither Congress nor FERC has ever compelled transmission owners to cede 

control over their transmission systems to independent operators, this Committee 

and Congress affirmatively encouraged this action by instructing FERC, through 

section 219(c) of the Energy Policy Act of 2005, to offer rate incentives to transmission owners that joined such organizations.1

This history of Congressional and FERC action introducing competitive forces to 

the utility industry is sometimes referred to as ‘‘deregulation.’’ But as was often 

noted by former FERC Chairman Joseph Kelliher, this terminology, particularly 

when applied to describe the functions of RTO/ISOs, is entirely misleading. In point 

of fact, FERC’s regulation of RTO/ISOs is pervasive. Moreover, unlike market regulators (such as the Securities and Exchange Commission and the CFTC) whose functions are probably best described as oversight based upon required disclosure, FERC 

is a traditional ‘‘rate regulator’’ with a mandate grounded in the Federal Power Act 

of 1935. What distinguishes FERC from those agencies overseeing the financial and 

commodity markets is its obligation to ensure that prices in wholesale electricity 

markets, and the terms and conditions of the various products and services used to 

establish prices in these markets, are ‘‘just and reasonable.’’ 

Each of the many functions performed by RTOs/ISOs as grid operators and market administrators is measured against this standard. Unlike clearinghouses, exchanges, boards of trade and the like, RTOs and ISOs cannot establish unilaterally 

their rules of operation provided only that those rules conform to broadly stated 

principles or best practices. Instead, RTOs/ISOs are subject to a FERC-administered 

program comprehensively regulating their planning of the transmission grid, their 

dispatch of generation operation of the grid, their compliance with reliability standards and their administration of the markets they operate. As a consequence, every 

material action taken by an RTO/ISO in performing these functions must be authorized by a rule. Every rule must be embodied in a tariff, which is designed through 

an open process with active participation by the customers subject to these rules. 

And every tariff provision must be filed with and adjudicated by the FERC to meet 

the requirements of the Federal Power Act.2

Moreover, RTOs/ISOs’ administration of markets cannot be separated from their 

operation of the grid. Rather, RTOs/ISOs rely on the markets they operate as tools 

to more efficiently dispatch generation, manage congestion on the grid and ensure 

that electricity procured through the RTO and ISO spot markets is provided at the 

least cost to wholesale customers. RTOs/ISOs operate according to the principle that 

competitive forces employed in transparent market environments provide price signals that incentivize behavior consistent with the reliable day-to-day operation of 

grid. 

4. Financial Transmission Rights in RTOs/ISOs 

(a) What is An FTR? 

I have spoken thus far of ‘‘products’’ and ‘‘environments.’’ The RTO/ISO environments offer a product known as a ‘‘financial transmission right’’ or FTR to ensure 
28 

3 Certain RTOs and ISOs operate forward capacity markets. These markets have even less of 

the attributes of a futures product than the FTR referenced herein. 4 As noted in the Joint Statement of RTOs/ISOs, Attachment A, other RTOs/ISOs make available similar products to what is known in PJM as a ‘‘Financial Transmission Right’’ or ‘‘FTR’’. 

Although the products may have a different name in each RTO or ISO, they all operate essentially the same. 5Pennsylvania-New Jersey-Maryland Interconnection, 81 FERC ¶ 61,257 at ¶ 62,240-241 

(1997). 

‘‘firm’’ transmission for electric transmission customers. Because this product is integral to the functioning of RTO/ISO markets, it has been in existence in PJM more 

or less since the inception of our markets. Despite successful operation of the FTR 

product, under FERC regulation, for more than 10 years in PJM, this product has 

recently drawn renewed attention from the CFTC.3

The FTR is a forward right or obligation with some attributes seen in swap contracts and other attributes seen in futures contracts.4 But several other essential 

attributes of FTRs are entirely unique so as to strain even the most liberal definition of a swap or futures contract, as those terms are employed, respectively, in the 

H.R. 3795 and the Commodity Exchange Act. Moreover, as I will explain, the FTR 

is a necessary component to the means by which RTOs/ISOs discharge their basic 

mission in providing open access transmission service and ensuring just and reasonable market outcomes for consumers—a mission whose regulation Congress has 

squarely entrusted to FERC. 

With the establishment by RTOs/ISOs of organized wholesale electricity markets, 

a system was needed to prioritize equitably firm access to the grid. Transmission 

customers, typically utilities and competitive suppliers serving retail consumers, pay 

a priority charge to receive ‘‘firm’’ transmission service. Firm service allows these 

customers to deliver, with a high degree of certainty, energy from resources located 

in one place on the grid to meet consumption located in a different place on the grid. 

Yet the ability of any transmission system to deliver electricity from point A to point 

B is limited by the physical capability of the system to transfer power within the 

bounds of the thermal and voltage constraints governing reliable operation of the 

system. 

The electricity markets operated by RTOs/ISOs typically employ a construct 

known as ‘‘locational marginal pricing’’ or LMP to signal demand for and attract 

supply of wholesale electricity. This means simply, that the real time price of electricity at point A may differ from the price at point B depending on whether the 

transmission system can deliver the lowest cost electricity generated by the marginal resource on the system to points A and B. As administered by RTOs/ISOs, 

LMP reflects the actual cost of delivering electricity from point A to point B in a 

manner corresponding to the physical flow of electrons on the grid between these 

two points. As compared to non-RTO/ISO transmission systems, LMP markets allow 

for a more efficient use of the transmission system by avoiding unnecessary curtailment of service and inaccurate and distorted pricing of transmission service whereby certain customers must subsidize in their rates the service provided to others. 

The provision of transmission service in LMP markets, however, exposes customers, 

including firm transmission customers, to price volatility when there is congestion 

on the grid. 

RTOs/ISOs solve this problem by providing firm transmission customers with 

FTRs. In a nutshell, these financial transmission rights provide the holder a right 

to deliver power from point A to point B with protection against the risk that prices 

at point B might be higher than at point A. PJM allocates FTRs principally to utilities that serve retail customers (including cooperatives, municipal utilities and competitive retail providers in those states with programs to instill competition in retail 

service). These rights in total reflect the physical capability of the transmission system to deliver electricity; they are finite and their number is determined through 

analyses conducted by the RTO/ISO. The allocation of these finite rights is made 

to those 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. The FTR is the means by which RTOs/ISOs 

in LMP markets assure the provision of ‘‘firm transmission,’’ consistent with FERC’s 

open access directives, such that these customers are protected against the price volatility associated with multiple transactions occurring through constrained parts of 

the grid.5

As I hope is apparent, the FTR is inextricably linked to both the locational priced 

energy markets and the provision of firm transmission service by RTOs/ISOs. It is 

also closely linked to the transmission system planning processes—the means by 

which the grid is expanded to meet growing need—another set of RTO/ISO functions 
29 

6 In this respect, an RTO/ISO and its FTR product is quite distinct from financial institutions 

and the derivative instruments they design and market. While a financial institution is seeking 

to expand the market for the instruments it sells, RTOs/ISOs are continuously examining opportunities to enhance the physical capability of the grid so as to reduce the need for FTRs. 

subject to extensive FERC regulation. In theory, a transmission system could be 

built to accommodate all desired delivery transactions without congestion—which is 

to say, without a price difference between points A and B. In this system, FTRs 

would be unnecessary. In fact, some might comment that the role of the RTO/ISO 

should be to design, build and operate a transmission system so robust as to eliminate FTRs.6 And while it is true that RTO/ISOs look for opportunities on their systems to eliminate points of chronic congestion by expanding transfer capability and 

thereby reducing the need for FTRs, in reality all transmission planners must strike 

a balance between the costs and societal tolerance for massive transmission infrastructure versus the costs of congestion. 

(b) FERC and Congress’ Historic Oversight of FTRs 

FERC Oversight—The FTR is rooted deeply both in FERC regulation as well as 

in actions of this Committee and the Congress as a whole. For instance, virtually 

from the inception of PJM’s markets, FERC directed the creation of FTRs as a 

means to allocate to transmission customers equitable access to the transmission 

grid. In PJM, the FTR product was approved by the FERC more than a decade ago 

upon the creation of PJM’s organized markets in 1997. In Pennsylvania-New JerseyMaryland Interconnection, 81 FERC ¶ 61,257 (1997), 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.’’ Id. ¶ ¶ 62,257, 62,260. FERC also concluded that PJM’s ‘‘allocation of FTRs’’ 

to transmission providers ‘‘to meet native load requirements (i.e. the customers for 

whom the transmission grid was planned and constructed in the first instance)’’ was 

appropriate. Id. ¶ 62,260. 

In connection with these approvals, the Commission further found that there 

needed to be ‘‘a process for auctioning FTRs beyond those retained by . . . transmission customers.’’ Id. ¶ 62,260. Accordingly, in 1999, and after considerable scrutiny, FERC accepted PJM’s design of an FTR auction process that would both (i) 

provide an efficient means to distribute excess FTRs, and (ii) allow FTR holders the 

choice to sell those FTRs which they had been allocated and buy FTRs on different 

pathways that might more effectively hedge their power supply procurements. PJM 

Interconnection, L.L.C., 87 FERC ¶ 61,054 (1999). 

Congress Has Directed FERC In Regulating FTRs—Congress’ recognition of FTRs 

in organized wholesale electricity markets and its involvement in directing FERC 

in its regulation of this product is most evident from Section 217 of the Energy Policy Act of 2005 (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. 

This direction to FERC (as well as Congress’ choice of FERC as the implementing 

agency) shows Congress’ intent to treat FTRs as tools available to load serving entities to meet their power supply needs rather than as another type of derivative instrument to be regulated separately and, perhaps, inconsistently, by the CFTC, 

which would claim no expertise or experience regulating the interstate transmission 

of wholesale electricity. 

Congress further underscored the inextricable link of these rights to the underlying physical delivery of power to customers by creating, in Section 217(b) (2), an 

actual entitlement for load serving entities: 

to use the firm transmission rights, or equivalent tradable or financial 

transmission rights, in order to deliver the output or purchased energy, or 

the output of other generating facilities or purchased energy to the extent 

deliverable using the rights, to the extent required to meet the service obligation of the load serving entity. 

Congress addressed how such rights are to be transferred by stating in section 

217(b) (3) (A) and (B) that: 

(A) To the extent that all or a portion of the service obligation covered by the 

firm transmission rights or equivalent tradable or financial transmission rights 
30 

is transferred to another load-serving entity, the successor load-serving entity 

shall be entitled to use the firm transmission rights or equivalent tradable or 

financial transmission rights associated with the transferred service obligation. 

(B) Subsequent transfers to another load-serving entity, or back to the original load-serving entity, shall be entitled to the same rights. 

Congress also addressed the disposition of any excess rights not needed to meet 

an entity’s load serving obligation by providing clear authority to FERC to address 

their disposition: 

CERTAIN TRANSMISSION RIGHTS—The Commission may exercise authority under this Act to make transmission rights not used to meet an obligation 

covered by subsection (b) available to other entities in a manner determined by 

the Commission to be just, reasonable and not unduly discriminatory or preferential. 

Finally, Congress directed FERC to undertake a rulemaking to implement portions of Section 217, a rulemaking that led first to FERC Order No. 681, a 250-page 

final rule on long term FTRs, followed by FERC Order No. 681-A, a subsequent rehearing Order on the subject, and, finally, compliance filings by the RTO/ISOs. 

In summary, through Section 217, Congress stated its intention that FERC regulate FTRs comprehensively, including their formation, initial allocation, and transfer 

among various entities, as well as the trading of any excess FTR rights available. 

PJM believes that Section 217 makes clear that the Congress intended for the 

FERC to act over FTRs because of their inextricable link to the underlying transmission grid and electricity market structure. The plain language of Section 217 indicates, in our opinion, Congress’ desire that the FERC’s regulation should be pervasive in this area, guided by its expertise in transmission regulation. 

As a result, PJM believes clarification is sorely needed given the uncertainties introduced as a result of the potential for an expansive reading of the existing Commodity Exchange Act or potentially from new financial reform legislation to introduce overlapping regulation by two separate agencies. 

5. The Problem Of Competing FERC and CFTC Jurisdiction 

As mentioned at the outset of my testimony, the wisdom in holding today’s hearing is that it offers an opportunity to confirm whether we are keeping our ‘‘eye on 

the ball’’ as we develop needed financial market reform regulation. Aside from reasons of inter-agency comity, inefficient duplicative regulation, and distraction, there 

are immediate and practical reasons to delineate clearly in statute the respective 

regulatory responsibilities of FERC and the CFTC when it comes to RTO/ISO products and environments. 

The notion of dual or overlapping jurisdiction in this area is challenged by the 

exclusivity of jurisdiction afforded to the CFTC through the Commodity Exchange 

Act and reinforced through proposed reform legislation. For instance, the existing 

Commodity Exchange Act states that where a contract falls under provisions of the 

Commodity Exchange Act, it is subject to the ‘‘exclusive jurisdiction’’ of the CFTC. 

See CEA § 2(a)(1)(A), 7 U.S.C. § 2(a)(1)(A). This grant of exclusive authority raises 

at least the potential that FERC could be divested of any jurisdiction over the FTR 

and any market settlement functions involving FTRs that the CFTC might regard 

as ‘‘clearing.’’ Yet, as I trust is evident from this testimony, the FTR does not stand 

in isolation from other market, grid operation and grid planning functions performed by RTOs/ISOs and that are regulated comprehensively by FERC. The FTR 

is not merely decorative to the architecture of RTO/ISO programs; it plays an integral role in the basic design of these programs. 

At least four concerns are apparent. 

First, the ‘‘exclusivity’’ provision of the Commodity Exchange Act could cause the 

FTR and its transaction and settlement functions being subjected to less control 

under CFTC oversight than they are today under FERC rate regulation. FERC’s 

regulatory paradigm of tariff filings and agency adjudication is considerably more 

extensive and intrusive than the market oversight performed by the CFTC. Neither 

the RTOs/ISOs that administer the transacting and settlement of FTRs nor industry 

participants in the FTR markets support an outcome that would result in less regulation of this product. 

Second, if the FTR is subjected to settlement, clearing and credit risk management principles well suited for many financial instruments, but incongruous to 

FTRs, the future of the FTR in RTO/ISO markets is quite uncertain. Again, this 

consequence might not be terribly problematic if the FTR could be regarded as a 

‘‘nice to have’’ risk management tool, but hardly indispensible to the needs of wholesale customers in managing their power purchases. As this testimony has tried to 

show, this is not the case. In fact, the FTR is essential to FERC’s policy of ensuring 
31 

7 CEA § 5b(c)(2), 7 U.S.C. δ 7a-1(c)(2). 8See, e.g., Transnor (Bermuda), Ltd. v. BP North America Petroleum, 738 F. Supp. 1472, 1990 

U.S. Dist. LEXIS 4423, Comm. Fut. L. Rep. (CCH) P24829, 1990-1 Trade Cas. (CCH) P68998 

(S.D.N.Y. 1990). 9Organized wholesale electricity markets have not operated without flaw since their inception—the notable example being a failure in 2001-02 in the western markets, including the market operated by The California ISO. Importantly, this failure had little or nothing to do with 

credit risk management or market clearing functions where the CFTC’s expertise lies. Rather, 

the problems at the time in that market are generally accepted to have resulted from (i) inadequate design of the complex rules defining the physical marketplace and (ii) actions by certain 

market participants to exploit these deficiencies. The CFTC would not profess expertise in this 

first area. And while its investigatory and enforcement expertise is exemplary, (i) effective enforcement in RTO/ISO markets demands a deep understanding of complexities characterizing 

the physical electricity market that only the FERC possesses, and (ii) since 2001-02, with pasContinued 

that transmission customers, in RTO/ISO environments, can obtain firm open access 

service needed to meet the demands of their retail consumers. The FTR’s importance to this objective is underscored by the attention this Committee paid to the 

product in the Energy Policy Act of 2005. 

Third, while the FTR auction markets attract some non-traditional energy market 

participants, including financial entities, it would be a mistake to therefore assume 

that these markets can be ‘‘cleared’’ under the Derivative Clearing Organization 

‘‘core principles’’ currently in place under the Commodity Exchange Act.7 The FTR 

is infrequently priced through pre-scheduled auctions that generally occur once a 

month. Buyers of FTRs are not in any legal sense matched with sellers. While PJM 

manages the credit risk exposure presented by holders of some FTR positions, these 

positions are not ‘‘marked-to-market’’ by PJM and there is no workable method for 

variation margining. Due to these and other attributes unique to FTRs and despite 

much exploration, PJM has never found a CFTC-registered clearinghouse, including 

those active in clearing energy commodity transactions, interested in or able to clear 

the FTR positions of PJM’s market participants. So, assuming that the practical 

consequences of CFTC oversight do not eliminate outright the FTR as PJM fears, 

the alternate scenario is one where the CFTC in bringing its expertise in overseeing 

market clearing and settlement, spends much time and resource requiring registration and reporting, only to find that no change or ‘‘improvement’’ to how our FTRs 

are transacted, settled and credit risk managed is achievable in a real or practical 

sense. 

Fourth, instruments traded in a manner or in an environment contrary to the requirements of the Commodity Exchange Act are, in a sense, ultra vires, and their 

enforceability is at risk of challenge.8 Somewhat ironically, the CFTC’s renewed interest in the established FTR products, motivated presumably by a desire to reduce 

perceived systemic risk associated with FTR markets, may be having quite the opposite effect. Should the CFTC claim that the FTR is now jurisdictional under the 

Commodity Exchange Act, the legal integrity of these products becomes less certain 

and a risk materializes that a counterparty with outstanding obligations under an 

FTR might assert that the obligation is void and unenforceable. Injecting this risk 

into the FTR markets is completely unnecessary and easily avoided by Congress 

drawing clear jurisdictional bounds that recognize FERC’s settled authority in this 

area. 

6. Complications Raised by the Wall Street Reform and Consumer Protection Act of 

2009 (HR 4173) and A Proposed Path Forward 

In closing, I would like to address the bill that passed the House of Representatives in December, 2009: the Wall Street Reform and Consumer Protection Act of 

2009 (HR 4173) and respectfully offer suggestions for an alternate path forward. 

The House Bill acknowledges existing and potential future overlapping jurisdiction between the CFTC and FERC in the area of RTO/ISO markets. It does not, 

however, seek to resolve this overlap; nor does the proposed legislation offer much 

by way of guidance to the affected agencies in collaborating to ensure RTOs/ISOs 

face a workable regulatory environment and one that does not afflict these markets 

with competing and inconsistent regulatory directive from separate agencies. Rather, the House Bill directs the CFTC and FERC to evolve a memorandum of understanding to resolve conflicting regulation and ensure cooperation and coordination 

where warranted. 

PJM believes legislation can, and should, reserve to FERC exclusive jurisdiction 

over the existing organized wholesale electricity market architecture administered 

by RTO/ISOs, which has operated effectively under FERC regulation for more than 

a decade.9 Similarly, new legislation offers the opportunity to reaffirm the CFTC’s 
32 

sage of the Energy Policy Act of 2005, FERC has been vested with significant additional enforcement authorities and resources. In short, reference to the events in the western markets in 

2001-02 is not a compelling basis to support the introduction of CFTC regulation to RTO/ISO 

markets. 10Legislation could offer guidance to the agencies in this area. For instance, Congress could 

instruct that one enforcement agency defer to the lead of the other in whose jurisdictional area 

the alleged scheme principally originated. 

existing exclusive jurisdiction over exchange and clearinghouse environments and 

provide that agency expanded authority in over the counter energy markets. 

This ‘‘bright line’’ would distinguish clearly RTO/ISO environments from other 

electricity trading environments and would afford market operators, such as PJM, 

certainty that the products and services they make available under their FERC-accepted tariffs do not need further registration or approval by the CFTC in order to 

be fully compliant and legally sound. This clarity at the ‘‘front end,’’ which is to say 

with the establishment and definition of the RTO/ISO’s products and services and 

the rules associated with them, will eliminate the potential of irreconcilable direction as to the same subject matter from different regulators. 

While perhaps desirable in theory, carrying forward this clarity beyond ‘‘front 

end’’ regulation to further define separate and distinct agency duties when it comes 

to the investigation and enforcement of fraudulent behavior or market manipulation 

(having ‘‘one cop on the beat’’) poses different challenges. Some degree of interrelationship among various trading environments is a reality that must be accepted 

in designing the optimum regulatory construct. A trading firm can put on a position 

in one market environment hoping to influence the value of other positions it may 

hold in a distinct market environment. This behavior is not uncommon and may be 

perfectly acceptable. But under particular circumstances such trading, coupled with 

fraudulent behavior and viewed holistically, could be manipulative or otherwise 

present an undesirable distortion of commodity prices. Where a scheme crosses two 

or more market environments implicating the respective jurisdictions of distinct regulators, inter-agency cooperation is plainly warranted in order to protect market integrity and consumer welfare. Legislation addressing concurrent FERC and CFTC 

enforcement jurisdiction should borrow from established principles of comity and cooperation that exist today among banking, securities and commodity regulators. By 

replicating these principles, legislation can either establish for the CFTC and FERC, 

or direct the agencies to themselves establish, similar protocols as are in place today 

between the CFTC and the Securities and Exchange Commission that describe 

shared duties and provide for more robust cooperation, including information sharing, when dealing with investigation and enforcement matters that cross agency 

boundaries.10

Finally, PJM is advocating for a ‘‘bright line’’ that would respect the existing 

FERC regulation of the current architecture of the electricity markets administered 

by RTOs/ISOs. While this architecture is regularly built out and redesigned by both 

FERC and the RTOs/ISOs themselves, legislation could anticipate the potential 

(which seems remote) for the RTO/ISO to develop in the future a wholly new class 

of products or programs that would be jurisdictional under the Federal Power Act, 

but also implicate provisions of the Commodity Exchange Act. The ‘‘bright line’’ we 

urge to protect the existing architecture of RTO/ISO markets from conflicting directives need not apply after the effective date of new legislation to wholly new programs—ones that cannot be envisioned today but might possibly evolve in RTO/ISOs 

at some future date. 

The following points and illustration summarize a possible legislative path forward: 

• Congress should define the status quo, as of the effective date of new legislation, and plainly state that the direct regulation over the products and services 

provided for by an RTO/ISO under its FERC filed tariff is exclusively the province of FERC. • Legislation can make equally clear that the direct oversight of electricity products (financial swaps, futures contracts, etc) in over-the-counter, exchange or 

clearinghouse environments is solely the responsibility of the CFTC. • Legislation can anticipate the possibility that RTOs/ISOs might develop in the 

future wholly new products or services, that while jurisdictional under the Federal Power Act and therefore offered under FERC-accepted tariffs, still cross 

into jurisdictional areas for which the CFTC has responsibility. In these cases, 

directing that the two agencies negotiate a workable sharing of functions could 

provide a compromise meeting the needs of both agencies. 

• Finally, legislation should distinguish between the direct regulation, oversight, 

reporting and rule compliance of market operators, from the important addi-
33 

tional responsibility imposed on each agency to investigate and prosecute manipulation and schemes undertaken by market participants that are designed 

and intended to distort pricing. Given the potential interrelationship among exchange, over-the-counter and RTO/ISO electricity markets, sound public policy 

warrants a high degree of inter-agency coordination, to allow information sharing and cooperation between the agencies in investigating and prosecuting 

fraudulent activities that span two or more interrelated market environments. 

7. Conclusion 

Again, PJM thanks the Committee for the opportunity today to share our 

thoughts on the potential for FERC and CFTC dual and potentially inconsistent regulation of certain RTO/ISO products essential to load serving entities and thus retail electricity customers. PJM’s fellow RTOs/ISOs that have endorsed the statements set forth in Attachment A also appreciate your consideration of their views. 

We stand ready to offer further assistance as the Committee reviews this important 

issue. 

ATTACHMENT A.—JOINT STATEMENT OF CALIFORNIA ISO, ELECTRIC RELIABILITY COUNCIL OF TEXAS (‘‘ERCOT’’), MIDWEST ISO, PJM INTERCONNECTION AND THE SOUTHWEST

POWER POOL

1. Financial transmission rights (FTRs) are an integral part of the provision 

of firm transmission service. Although they go by different names in each of the 

RTOs and ISOs, the products are essentially the same. FTRs are awarded, initially to load serving entities (i.e., providers of electricity to residential, commercial and industrial customers) and others who contribute to the fixed costs of 

the grid through their payment of transmission rates. These customers have 

historically shouldered the embedded costs of building and maintaining the 

transmission system. 

2. FTRs are a financial instrument that can be created only by the RTOs/ISOs 

as their number and composition is determined based upon the transmission 

system topology and the physics of physical power flows. As such, they differ 

substantially from standardized, stand-alone derivatives in which parties exchange cash flows based upon price changes tied to a notional quantity of a 

commodity, but not inextricably tied to the actual delivery of a physical commodity. Moreover, because FTRs are inextricably intertwined with the electricity markets and reliability functions of RTOs and ISOs, it is impractical and 

inefficient to regulate FTRs separately or differently from the underlying provision of electric transmission service. 

3. FTRs have been regulated by the FERC (and in the case of ERCOT, the 

Public Utility Commission of Texas) since their inception in the PJM market 

over 10 years ago. In addition, Congress determined in EPACT 2005 that FTRs 

are integrally tied to meeting the power procurement needs of load serving entities. FERC not only regulates FTRs, but FERC directed PJM and other ISOs/ 

RTOs to develop a hedging tool to allow load serving entities to manage congestion risk associated with their longer term power procurements. By the same 

token, the portion of the Texas grid served by ERCOT is entirely intrastate. As 

a result, regulation of FTRs in Texas is undertaken by the Public Utility Commission of Texas in a fully integrated manner. 

4. Duplicative or conflicting regulation of financial transmission rights is not 

in the interest of consumers. FERC (and, in the case of ERCOT, the Texas PUC) 

should be able to maintain their respective roles as the regulators of these products given their pervasive regulation of both ISO/RTO markets and the provision of transmission service by ISOs/RTOs. This regulation comprehensively 

spans the full span of physical grid operations—from the planning of the transmission grid, to ensuring day to day reliability of the grid, to the dispatch of 

generation and demand resources to meet consumption in real time. The uncertainty created by the unclear regulation of FTRs under current law as well as 

complications created by the provisions of the new legislation should be addressed in the legislation now being considered. 

5. Although the RTOs and ISOs do not believe that Congress intended there 

be two regulators of the FTR product, the RTOs and ISOs do believe that cooperation is needed in areas where activities in a CFTC-regulated market may 

affect a FERC or Texas PUC-regulated market and vice versa. This is not an 

area of regulatory overlap, but instead an area where the exercise of the authority of each regulator over their respective jurisdictional market should be coordinated and complementary. As a result, cooperation, including data sharing, 

should be required by this Congress in those areas where FERC’s or the Texas 
34 

PUC’s regulation of the RTOs and ISOs has an impact on CFTC’s regulation 

of markets under its jurisdiction and vice versa. 

The CHAIRMAN. Thank you very much. 

Next is the Honorable Joseph Kelliher who used to be head of 

FERC, of course, and we are glad to have him back before the committee. Go right ahead. 

STATEMENT OF JOSEPH T. KELLIHER, EXECUTIVE VICE 

PRESIDENT, FEDERAL REGULATORY AFFAIRS, FPL GROUP, 

INC., ON BEHALF OF THE EDISON ELECTRIC INSTITUTE AND 

THE ELECTRIC POWER SUPPLY ASSOCIATION 

Mr. KELLIHER. Thank you, Mr. Chairman, Ranking Member 

Murkowski, and members of the committee. I appreciate the invitation and it is good to be back before the committee. I took care to 

sit in Jon’s seat when Chairman Wellinghoff got up. I thought that 

was the right seat for me to take. 

Thank you for the invitation to testify today on financial transmission rights and electricity markets and how that regulation may 

be impaired by financial regulatory reform legislation. 

I do also want to take the opportunity to offer views on over-thecounter energy commodities transactions and the need for an energy end-user exemption from any mandate to force OTC transactions onto exchanges. 

I am testifying today on behalf of EEI and EPSA. 

As FERC chairman, I was on the giving end of regulation. I am 

now on the receiving end of regulation, and it is a different perspective. But I want to offer both perspectives on really 2 fundamental questions before the committee and before the Senate: one, 

whether there should be an energy end-user exemption from any 

mandate to force exchange trading; and 2, whether exclusive FERC 

regulation of wholesale power and gas markets should be bifurcated by the introduction of CFTC regulation. We believe that, one, 

there is a need for an energy end-user exemption and that, 2, exclusive FERC regulation should not be disrupted by the introduction of CFTC regulation. 

EEI and EPSA support the goals of the administration and Congress to improve transparency, stability, and oversight of financial 

markets, including OTC derivatives markets. We do not disagree 

with the need for derivatives reform generally, but the rationale for 

OTC derivatives reform is to lower systemic risk and lower costs 

through transparency. However, energy derivatives, energy commodities played no role in the 2008 financial crisis. Energy commodity trading poses no systemic risk. Commodities as a category 

represent about 1 percent of derivatives and energy commodities 

are a slice of that 1 percent. So forcing exchange trading will not 

reduce risk associated with energy commodity trading, but it will 

have significant real costs to consumers. 

The collateral requirements will be tremendous, on the order of 

hundreds of millions of dollars for electricity companies. One example is with respect to PJM. Requiring electricity suppliers and 

PJM—last month, PJM held an auction. There was an auction in 

New Jersey. New Jersey acquires electricity supply for its utilities 

through an auction. That auction—New Jersey utilities purchased 

2,500 megawatts for a 3-year term last month. If that entire vol-
35 

ume were forced to trade on an exchange, electricity suppliers 

would have had to post about $1 billion in collateral, and that $1 

billion would have been added to the bids into the New Jersey market and that $1 billion would have been borne by New Jersey consumers. So dead capital used for collateral is better used elsewhere 

in a capital-intensive industry, for infrastructure such as new generation or transmission, for Smart Grid projects, energy efficiency, 

technology, clean energy projects. 

So while we disagree with the merit of forcing exchange trading, 

we agree on the need for greater transparency. We think that can 

be achieved with the reporting requirements rather than forcing 

exchange trading. So we do think there is a need for an express 

energy end-user exemption and that that exemption should not be 

too narrow. 

With respect to FERC regulation, I think there is a need for legislation to protect FERC’s regulatory authority over FTRs and 

other energy products. There is, in my view, no justification for financial reform legislation to reform the regulation of wholesale 

power and gas markets that, frankly, require no reform. I think 

legislation should clarify the electricity products and services provided under FERC-approved tariff and subject to FERC regulation 

should be exempt from duplicative regulation by the CFTC. 

One example is FTRs. FERC has exclusive jurisdiction over 

transmission service. FTRs are inextricably connected to transmission open access service. They are a central means by which 

FERC assures transmission customers have firm, open access 

transmission service. A shift in jurisdiction would undermine open 

access transmission, something that has been important to Congress for 30 years. 

The stated rationale to introduce CFTC regulation of FTRs is the 

need to close a loophole, but I respectfully submit that there is no 

loophole. There is no regulatory gap. FTRs are comprehensively 

regulated by FERC. There is no need to subject these transactions 

to duplicative regulation. FTR auctions are governed by tariff rules 

set by FERC. The FTR transactions are fully transparent and that 

information is available through RTO Web sites. FTR markets are 

subject to the FERC anti-manipulation rule and FERC has conducted investigations of alleged manipulation of FTR markets. So, 

in short, there is no gap. 

The House bill included an MOU that purported to address the 

regulatory concerns between FERC and CFTC jurisdiction, and I 

respectfully suggest that the MOU in the House bill will prove a 

completely ineffective means to resolve jurisdiction between the 2 

agencies. I think Congress decides jurisdiction not agencies. That 

FERC and CFTC have an honest disagreement on interpreting the 

law, a disagreement that goes back 3 years, the disagreement revolves around the ambit of FERC’s anti-manipulation authority. 

That disagreement, I respectfully suggest, is not going away. But 

at this point, only courts or Congress can resolve the dispute between the agencies because it is, I think, an honest disagreement. 

They are reading the law differently. Then an MOU is no sort of 

resolution to the question. 

So with that, I thank you for the opportunity to testify, and I am 

happy to answer any questions you might have. Thank you. 
36 

[The prepared statement of Mr. Kelliher follows:] 

PREPARED STATEMENT OF JOSEPH T. KELLIHER, EXECUTIVE VICE PRESIDENT, FED- ERAL REGULATORY AFFAIRS, FPL GROUP, INC., ON BEHALF OF THE EDISON ELEC- TRIC INSTITUTE AND THE ELECTRIC POWER SUPPLY ASSOCIATION

Mr. Chairman, Ranking Member Murkowski, and Members of the Committee: My 

name is Joseph T. Kelliher, and I am Executive Vice President—Federal Regulatory 

Affairs for FPL, Group, Inc. I appreciate the opportunity to appear before you today 

to testify about how financial transmission rights and other electricity market mechanisms may be impacted by the financial regulatory reform legislation which has 

passed the House of Representatives and is before the Senate. 

FPL Group is a public utility holding company headquartered in Juno Beach, 

Florida. FPL Group is one of the Nation’s largest electricity companies, a premier 

clean energy company with two principal electric subsidiaries, NextEra Energy Resources, LLC, a competitive generation company that operates in 26 states and is 

the largest wind developer in the .United States, and Florida Power & Light Company, a vertically integrated utility in Florida. These two FPL Group companies 

own, operate or control nearly 43,000 megawatts of electric generation facilities. The 

issues the Committee is examining today are equally important to both NextEra Energy Resources and Florida Power and Light Company. They are as important to 

the ability of a vertically integrated utility to deliver reasonably priced electricity 

as they are to the ability of a wind developer and independent power producer to 

sell their electricity output. 

At FPL, Group, I am responsible for federal regulatory policy for both NextEra 

Energy Resources and Florida Power and Light Company. I have spent my entire 

professional career working on energy policy matters, serving in a variety of roles 

in both the public and private sectors. Previously, I served as Chairman of the Federal Energy Regulatory Commission (FERC), a FERC Commissioner, a senior policy 

advisor to the Secretary of Energy, and Majority Counsel to the House Energy and 

Commerce Committee. I also have had a variety of private sector roles. 

While FERC Commissioner, I asked Congress during development of the Energy 

Policy Act of 2005 to grant FERC authority to prevent and penalize market manipulation. I did so because I believed there was a regulatory gap in FERC’s authority 

to prevent market manipulation that needed to be filled. During my chairmanship 

FERC implemented its anti-manipulation rules and began to conduct market manipulation investigations. Many of these investigations were conducted jointly with the 

Commodity Futures Trading Commission (CFTC). Some FERC enforcement actions 

have resulted in jurisdictional disputes between FERC and CFTC. 

I am testifying today on behalf of the Edison Electric Institute (ELI) and the Electric Power Supply Association (EPSA). ELI is the trade association of U.S. shareholder-owned electric companies, with international affiliates and industry associate 

members worldwide. The U.S. members of ELI serve 95 percent of the ultimate electricity customers in the shareholder-owned segment of the industry and represent 

about 70 percent of the total U.S. electric power industry. EPSA is the national 

trade association for competitive wholesale power suppliers, including generators 

and marketers. EPSA members include both independent power producers and the 

competitive wholesale generation arms of certain utility holding companies. The 

competitive sector operates a diverse portfolio that represents 40 percent of the installed generating capacity in the United States. EPSA members do business nationwide, both in the two-thirds of the country served by Regional Transmission Organizations (RTOs) or Independent System Operators (ISOs) and the remaining onethird of the country dominated by traditional vertically-integrated utilities. My examples and context are from FPL Group’s perspective but are representative of EFT 

and EPSA member concerns and requests. 

My testimony today: 

• Details the importance of over-the-counter (OTC) derivatives to well-functioning 

electric markets and explains the need for a specific energy end-user exemption 

from any mandate that OTC transactions clear or trade on CFTC-regulated exchanges; and 

• Requests that the Committee support legislation to clarify that electricity products and services provided under a FERC-approved tariff and subject to regulatory oversight by FERC, such as financial transmission rights (FTRs), should 

be exempt from duplicative regulation by the CFTC. 

EEI and EPSA support the goals of the Administration and Congress to improve 

transparency, stability, and oversight of financial markets, including OTC derivatives markets. However, when crafting legislation for that purpose, it is essential 
37 

1See October 2, 2009 letter to Members of the U.S. House of Representatives and February 

3, 2010 letter to Members of the U.S. Senate from the Coalition for Derivatives End-Users (attached). 2See January 21, 2010 letter to Members of the U.S. Senate from the Energy End-Users Coalition (attached). 

that policymakers preserve the ability of electric and natural gas companies to use 

OTC energy derivatives and similar financial products and FTRs for prudent, legitimate business purposes. A large group of end-users has communicated this message 

to Congress on numerous occasions).1 Further, a group of energy end-users that includes virtually the entire utility, electric power and natural gas industries has also 

emphasized the importance of these products to the energy sector.2 Utilities, independent electricity generators, renewable energy providers, and other market participants rely on these products and markets to manage wholesale electricity and 

natural gas price risk. By prudently managing our risk we are better able to keep 

rates stable and affordable for our consumers. 

I recognize that this Committee does not have jurisdiction over the financial market reform legislation. However, you do have a very important jurisdictional issue 

at stake: Unless it is properly crafted, the financial market reform legislation will 

encroach upon this Committee’s jurisdiction over electricity and natural gas markets 

regulated by FERC under the Federal Power Act and the Natural Gas Act. Specifically, it could interfere with wholesale electricity markets under FERC’s jurisdiction 

that are managed and overseen by RTOs and ISOs and the market under the Public 

Utility Commission of Texas’ jurisdiction in the case of the Electric Reliability Council of Texas (ERGOT). It could create a duplicative, overlapping and potentially conflicting regulatory regime with both FERC and the CFTC imposing regulatory requirements and overseeing transactions. It could shift regulatory jurisdiction from 

a consumer protection and reliability agency with expertise in electricity markets— 

an agency dedicated to assuring just and reasonable prices—to a financial regulatory agency with no such background or duty. The legislation will create tremendous regulatory uncertainty and introduce regulatory and business risk in an area 

where there is now repose. As a result, consumers would see higher prices for electricity and natural gas and greater price volatility. 

As I will explain, RTOs and ISOs efficiently dispatch generation resources to minimize fuel costs and enable the RTO/ISO customers (utilities, generators, marketers) 

to manage the cost of congestion on the transmission system by the use of FTRs. 

In our parlance, customers use FTRs to ‘‘hedge’’ their congestion costs. Some may 

argue that FTRs resemble a derivative product or swap that should be subject to 

the CFTC’s jurisdiction. Indeed the RTOs and ISOs themselves could be subject to 

the CFTC’s jurisdiction unless the reform legislation is properly crafted. However, 

in contrast to derivatives, FTRs are integrally tied to the physical delivery of electricity and must be physically feasible. Moreover, they provide a uniquely important 

hedging tool to electricity suppliers and consumers who produce, transport, and consume electricity on a continuous basis and do so in a fully transparent market. In 

addition, FTRs already are comprehensively regulated by FERC and the RTOs and 

ISOs themselves. There simply is no need to subject these transactions and organizations to costly, duplicative and potentially conflicting oversight by two agencies. 

This Committee clearly has a strong interest in making sure the legislation does not 

encroach on FERC’s oversight authority over electric and natural gas markets. 

The Administration has called upon Congress to enact major financial reform legislation because of the dramatic failures we have experienced in financial markets 

and failed government oversight of those markets. Those failures simply are not 

present in electricity and natural gas markets regulated by FERC. In short, there 

is no regulatory gap that needs to be filled by expanded CFTC authority over markets currently effectively regulated by FERC. 

When considering any increased regulation and requirements for OTC derivatives 

markets, it is important to note that end-user commodity derivatives transactions 

do not pose the type of ‘‘systemic risk’’—i.e., ‘‘too big to fail’’—that Congress is seeking to eliminate through the proposed legislation. In fact, from a quantitative perspective, the entire commodities market is less than one percent of the global OTC 

derivatives market, and the energy commodity portion is only a fraction of that one 

percent. Therefore, we believe that Congress should strike the proper balance in its 

regulatory reform efforts by establishing energy market oversight rules that allow 

for prudent use of OTC risk management products while also providing regulators 

with the tools needed to protect consumers against market manipulation and systemic risk. 

With its competitive power company, renewable energy provider, and vertically integrated utility, FPL Group looks at the impact of financial reform legislation from 
38 

the perspective of our customers, who are wholesale and retail electric consumers. 

We certainly support the goal of financial regulatory reform, but the ability of electric and natural gas companies to use OTC energy derivatives for legitimate business purposes should be preserved. In addition, the CFTC should not have the authority to regulate wholesale electricity markets and transactions that are already 

subject to a FERC-approved tariff. This would result in costly, duplicative and overlapping regulation over our sector. The balance of my testimony focuses on that 

problem. 

I will briefly describe and explain: (i) why utilities and electricity generators use 

FTRs and OTC derivatives products; (ii) the cost to consumers of unnecessary overregulation of these OTC derivatives transactions; and (iii) why FERC has and 

should retain exclusive jurisdiction over wholesale electricity markets. 

To understand the role of FTRs and OTC derivatives in wholesale electricity markets, I will begin with a short explanation of how those markets are currently structured and regulated. Most of NextEra Energy Resource’s generation assets operate 

within RTOs or ISOs. In fact, over 65% of Americans, or 134 million customers, live 

in regions served by RTOs and ISOs. These organizations administer formal, ‘‘organized’’ wholesale electricity markets; these markets are subject to detailed rules and 

oversight by FERC. Utilities are required to file tariffs to comply with FERC’s requirements. These organizations also operate the electric grid in their areas and 

independently administer transmission assets to ensure access to transmission on 

a nondiscriminatory basis. RTOs and ISOs also have independent market monitors 

who certify that these markets are operated fairly and without unmitigated market 

power. All RTOs and ISOs and the transactions that occur in them currently are 

regulated exclusively by FERC (except: ;RCOT, which is regulated by the Public 

Utility Commission of Texas). 

When RTOs and ISOs were first organized, the utility members retained their 

rights to move electricity from their generators to their customers by using physical 

transmission ‘‘paths.’’ Administering a physically-based system of transmission 

rights proved to be both cumbersome and inflexible over time. And it was not very 

good at managing congestion. The problem with these physically-based systems is 

that the demand for electricity varies by a factor of two every day, and so the economic pattern of transmission flows varies from hour-to-hour and day-to-day. A 

fixed set of physical transmission rights does not fit this reality. 

As RTOs and ISOs evolved, and their markets became more efficient—which 

means less expensive for consumers—the system of physical transmission rights 

evolved to a system of financial transmission rights or FTRs. FTRs are also an integral part of markets that are based on locational marginal pricing with security constrained economic dispatch (also known as LMP pricing), which I will discuss briefly 

below. All RTOs and ISOs have adopted, or are moving to adopt, a form of LMP, 

though some of the details vary from region to region. LMP has proven to be the 

most efficient way within an RTO to take maximum advantage Of the physical capability of the transmission system while maintaining reliability. LMP provides the 

mechanism to dispatch generation according to which generators are the least expensive to run at the time they are needed to serve the load. 

FTRs are integral to the proper functioning of competitive electric markets. FTRs 

allow electric market participants to manage their electricity and transmission price 

risk when delivering power on the grid. 

However, in order to better understand FTRs, one must understand LMP. In 

RTO/ISO electricity markets, generators receive the ‘‘locational’’ price for the electricity they put on the grid at what is known as the ‘‘point of injection.’’ The utilities, known as local distribution companies (or LDCs), pay the locational price at 

the point where they withdraw power from the grid. Differences in these two locational prices typically arise as a result of congestion on the transmission system. 

Congestion is like a kink in a hose. The transmission system is too clogged to allow 

lower cost generation on one side of the kink to flow to the other side. That means 

a higher cost generator runs even though a lower cost generator is available elsewhere on the transmission system—that is behind the kink. Consequently, where 

there is a difference between these two prices, the generator or LDC will be subject 

to congestion fees that are paid to the RTO/ISO. 

In order to give market participants the ability to manage the differences in the 

locational prices, RTOs and ISOs sell, or auction, FTRs on a long-term, year-ahead 

and short-term basis. Ownership of an FTR thereby allows the entity to recoup 

some of the congestion fees. But these FTR markets are already heavily regulated 

by the FERC: 

• RTOs sell a quantity of FTRs that corresponds to the capacity of the transmission system—neither more nor less. So the ‘‘supply’’ of FTRs is based on the 
39 

physical characteristics of the transmission system and regulated consistent 

with that; 

• The auctions are designed to sell FTRs in combinations that are most highly 

valued by market participants—and the auctions themselves are governed by 

tariff rules established by FERC; 

• Auction proceeds go to transmission owners and LDCs; 

• Ownership of an FTR does not allow a market participant to change the value 

of that FTR; vrR transactions are fully transparent—the ownership of each FTR 

is available for all to see on RTO/ISO web sites; 

• Settlement or payouts of FTRs are based on bidding by generators and loadserving entities for power sales and purchases, consistent with anticipated 

power production and consumption by market participants and reflecting congestion on the transmission system; and 

• FTR markets are subject to FERC’s anti-manipulation rule. 

The auctions have detailed rules about how FTRs can be purchased. As a general 

rule, the FTRs auctioned by the RTOs are those that have not already been claimed 

by the LDCs, who have preferential access to FTRs. In addition, FTR holders are 

subject to credit requirements. The RTOs and ISOs administer the FTR markets, 

subject to FERC’s extensive oversight. There is no regulatory gap and there is no 

basis to introduce duplicative regulation of this market. 

Generators and LDCs buy FTRs to manage, or hedge, the amount they will have 

to pay for congestion. Without the ability to hedge this risk, costs would go up, and 

customers would be subject to the volatility that results from the all-too-regular occurrence of transmission congestion. Some have criticized the fact that non-utility 

players are involved in the market for FTRs. But it is essential to have a variety 

of players and the liquidity they bring to the market. The market monitors also review all of the above. 

Another way that generation companies manage risk is by entering into transactions to sell some of the electricity that they will generate in advance. They do 

those transactions with credit-worthy counterparties. For example, a generator 

might sell an amount of electricity for one agreed price for all hours in the summer 

months of June through September. The generator will then know that it will always get that price for that amount of electricity during those four months. The generator foregoes the prospect of getting higher prices absent the sale but, more importantly, it avoids the risk that prices will fall below the fixed price it is paid by 

the buyer of the electricity. A generator also can do the same thing with respect 

to the fuel it buys to run the plants. The generator might transact in the OTC market for natural gas or lock in fuel costs for its gas power plants. 

Risk management is also important to clean energy companies. NextEra Energy 

Resources is the leading wind energy company in the United States. While most of 

the output from our wind projects is sold under power purchase agreements, we do 

operate some merchant wind projects that sell into the market on a daily basis. 

Many other wind energy companies in the U.S. rely heavily on merchant sales. 

Wind energy companies hedge the power output of merchant wind projects to provide necessary certainty to support project financings and corporate earnings projections. As an example, a company can sell the physical output from its wind projects 

into the daily market and receive the daily market floating price for power. To 

hedge the risk of price volatility in the daily markets, the company could enter into 

a ‘‘fixed for floating power swap’’. A typical power swap transaction would involve 

the wind energy company receiving a fixed price for power from a counterparty 

(typically a bank) and paying the daily market floating price for power to that 

counterparty. 

Another way to manage risk is through put options that provide downside price 

protection for merchant wind project financings. A put option provides a company 

with the right to sell power to a counterparty (typically a bank) at a strike price 

and in return the company pays the bank an upfront premium for this option. As 

an example, assume the current power market was $50/MWh, but a power price of 

only $40/MWh was required to provide sufficient cash flows to support the debt payments in a project financing. The company could enter into a power put option; pay 

a counterparty an upfront premium for the right to sell power to them with a strike 

price of $40/MWh. If the price of power dropped below $40/MWh, the company 

would have the right to sell power to the counterparty for $40/MWh to protect 

project cash flows. If the price of power went up to $60/MWh, the company would 

continue to sell power into the daily market and would not exercise the put option. 

The growth of clean energy could result in new products to manage risk, such as 

a weather derivative for wind resources. The concept would be for a counterparty 

to take on the variability of the wind resource as measured against a long-term his-
40 

torical wind index. The wind energy company would receive a payment from the 

counterparty if the wind resource came in lower than the historical average wind 

index and pay the counterparty if the wind resource came in higher than the historical average wind index. 

It would be difficult to support a merchant wind business without having OTC 

derivatives available to hedge market price risk. Banks would be unwilling to lend 

money without the ability for projects to lock in prices and provide certainty on 

project cash flows. These types of nonstandard, or customized, products are important to the wind business. 

Our customers benefit from this hedging and trading activity. We are in a position 

to agree to longer-term power sales contracts with wholesale customers; the price 

terms under those contracts are in large part possible because of the relative price 

stability that hedging provides to our portfolio. It is our experience that retail customers in particular want prices for power sales to be stable rather than subject to 

the fluctuations and uncertainties of the spot market. Without hedging and trading, 

we simply would not be able to do that. 

These types of hedging transactions are not always done on an exchange because 

we tailor the product we sell to the needs of the purchaser; in other words, these 

are not necessarily standardized products. Even certain products that could be considered standardized are often contracted for under specific, customized delivery, 

credit or capital terms. 

In RTO/ISO markets, electric utilities that have divested their power plants must 

buy power to serve their customers. In the Northeast and Mid-Atlantic states, utilities periodically enter the market to purchase full requirements service to meet 

their load obligations. These transactions are highly customized. The products sold 

include energy in quantities that match the utilities’ load in each hour of the day 

delivered to the utilities’ service territory. The utility also passes system balancing 

costs and transmission costs to the seller as part of the transaction. These transactions are highly customized and cannot be executed on an exchange. Energy companies that make these customized sales often hedge their positions with standardized products. 

Some would argue that advance sales of power, where the price is based upon an 

average of other sales or an index, are futures transactions and would subject them 

to the CFTC’s exclusive jurisdiction. We disagree. These are wholesale and retail 

power sales already regulated by FERC and state utility commissions, respectively, 

and should not be regulated by the CFTC. 

NextEra Energy Resources would not be able to offer customized products greatly 

valued by customers if it could not hedge its future price risk. Requiring NextEra 

Energy Resources to conduct all of its transactions on exchanges, with standard 

rather than customized contracts to meet its customers’ needs, and subjecting those 

transactions to costly central clearing requirements, would undoubtedly result in 

significant price increases for its customers. These examples illustrate why we support an end-user exemption for both wholesale and retail market participants. 

In addition to concerns about FTRs and other hedging activities, I want to mention a concern that the RTOs and ISOs themselves could arguably become subject 

to the CFTC’s jurisdiction as ‘‘derivatives clearing organizations’’ under some 

versions of the financial reform legislation. RTOs and ISOs routinely settle hundreds of millions of dollars of financial transactions entered into by their markets’ 

participants. If any of those transactions are classified as derivatives transactions, 

the RTOs and ISOs could be classified as derivatives clearing organizations to the 

extent that they provide ‘‘clearing’’ services for the transactions. That, in turn, could 

mean that these organizations themselves would be subject to the CFTC’s jurisdiction, in addition to the FERC’s jurisdiction. This would add untold complexity and 

expense, and drive up the costs of these organizations, which would be passed on 

to electricity consumers. 

The Senate Banking and Agriculture Committees are considering financial reform 

legislation that may subject all of the types of transactions I have described above 

to the CFTC’s jurisdiction. Some versions of the proposed legislation would require 

transactions that are now done ‘‘over the counter’’ to be cleared and/or traded on 

CFTC-regulated exchanges. The requirement to clear and/or trade such transactions 

on an exchange would materially increase both wholesale and retail electricity 

prices. Transactions conducted on an exchange are subject to substantial margin requirements, while transactions that are not conducted on an exchange do not have 

the same margin requirements. The consequences of the margin requirement are 

significant. 

Today, credit-worthy companies like NextEra Energy Resources and Florida 

Power & Light routinely engage in OTC derivative transactions with other creditworthy counterparties. These transactions are often not subject to a margin require-
41 

ment due to the creditworthy nature of the parties. Rather we typically rely on each 

other’s balance sheets, or the value of other assets, as security for the trade. However, margin is typically required only when exposure has reached a mutually 

agreed upon limit. Exposures above such limit are then subject to margining requirements. Thus parties to off-exchange transactions pay less overhead, which benefits our customers. 

Analysis by members of the large end-user energy group previously mentioned 

has found that the increased costs of forced trading on exchanges would be hundreds of millions of dollars for the average utility or generation company. The margin requirement would tie up large amounts of cash, creating ‘‘dead’’ capital at a 

time when the power sector faces the need to invest hundreds of billions of dollars 

in clean energy technologies, energy efficiency, the smart grid, and additional transmission capacity. 

It is critical that these companies continue to have access to the OTC market for 

these hedges. Requiring suppliers to hedge on an exchange would expose them to 

significant liquidity risk for cash margining. The cost of this risk would ultimately 

be borne by the utilities’ customers via higher prices charged for the full requirements service. For example, in February utilities in New Jersey purchased approximately 2,500 MW for a three-year term. If this entire volume were hedged on an 

exchange, suppliers would have had to post about $1 billion in cash to cover initial 

margin and variation margin. This $1 billion would have been added to bids accepted for the auction and ultimately would have been borne by consumers in New Jersey. There are a number of other states that conduct similar auctions. They would 

face a similar cost premium to reflect the additional working capital costs that suppliers would have to bear if the OTC markets are not available for the hedging 

needed to provide these types of products. Competition would also decline as the liquidity risk would simply be unacceptable to many suppliers. It is a basic tenet of 

markets that fewer participants would result in higher prices to customers. 

Therefore, if financial reform legislation requiring clearing for these transactions 

were enacted, consumers would see their prices increase because an additional and 

unnecessary layer of cost would be added to the marketplace—without a commensurate reduction in risk. 

Initial reform proposals have included a number of vague or ambiguous terms 

that will need to be clarified prior to passage of a final measure. The aim of all of 

the financial reform proposals has always been to focus on the large financial players whose transactions can pose systemic risk. Without a specific exemption, it will 

not be clear whether electricity end-users are also intended to be covered and subject to the various new requirements. Something this important and costly needs to 

be clear and should unambiguously exempt end-users managing commercial risk 

from the clearing and exchange-trading requirements. Unless the terms of the legislation are precise, determining which parties and transactions are subject to a clearing requirement will be left to the broad discretion of the CFTC. CFTC Chairman 

Gensler and his staff have stated on numerous occasions the position that virtually 

all OTC transactions, including FTRs, should be cleared or traded on exchanges; we 

respectfully disagree. 

As a result, we believe that the legislation should clarify that FERC is the sole 

regulatory authority governing electricity products and services provided under a 

FERC-approved tariff and subject to regulatory oversight by the FERC, with the 

same true for the Public Utility Commission of Texas for ERGOT. 

It is important for Congress to make clear that FERC retains exclusive authority 

under the Federal Power Act over all wholesale electric markets and transactions 

subject to a FERC tariff. As indicated in the discussion of FTRs, financially settled 

transactions are an integral component of RTO/ISO markets. Consistent with the 

purposes of the Federal Power Act, they ensure the efficient and reliable physical 

generation, transmission and wholesale delivery of electricity at just and reasonable 

rates. In addition to the Federal Power Act authority, FERC has a duty under the 

Energy Policy Act of 2005 to ensure these markets are not subject to manipulation 

or abuse. 

Wholesale electricity markets are already pervasively regulated by FERC, and the 

introduction of CFTC regulation either creates duplicative regulation or transfers 

FERC jurisdiction to the CFTC. It does not fill a regulatory gap, since there is no 

gap in this area. If there are two regulators, the rules will inevitably be different 

depending upon which agency imposes them. Gamesmanship, abuse and market 

manipulation all thrive under this kind of overlapping and confusing regulation. In 

my view, bifurcated jurisdiction of these markets will invite market manipulation. 

Clear and unambiguous authority for FERC to regulate these transactions is essential. There is already litigation over which agency has authority to police manipula-
42 

3 CS-1 Resolution on Financial Reform Legislation Affecting Over-the-Counter Risk Management Products and Its Impacts on Consumers, adopted by the NARUC Board of Directors, February 17, 2010 (attached). 

tion by futures market participants that affects FERC jurisdictional markets. We 

cannot afford further confusion over regulatory jurisdiction. 

Some have suggested that the problems created by duplicative oversight over 

these markets by both FERC and the CFTC could be worked out by directing the 

two agencies to enter into a Memorandum of Understanding delineating who will 

do what. I believe that approach will be ineffective. As I indicated earlier, the Commodity Exchange Act confers upon the CFTC ‘‘exclusive’’ jurisdiction over certain aspects of futures transactions, namely futures trading on exchanges Other CFTC authority is non-exclusive. FERC and CFTC disagree on their respective authority 

under current law, reflected in litigation over FERC’s efforts to police alleged market manipulation by futures participants that affected FERC-jurisdictional markets. 

This is an honest disagreement, but one that is fundamental and has persisted for 

years. There is no reason to believe this disagreement will disappear, especially if 

Congress enacts legislation that grants CFTC additional discretionary authority in 

any legislation with significant ambiguity and replete with undefined terms. The 

House bill appears to leave it up to CFTC to determine where FERC jurisdiction 

ends. The plain fact of the matter is that FERC and CFTC disagree on their respective legal authority under current law. The enactment of legislation such as the 

House bill would only sharpen that disagreement. To the extent there is disagreement between two federal agencies on how to interpret their legal authority, that 

disagreement can only be resolved by the courts or Congress, not by a Memorandum 

of Understanding between agencies with a good-faith disagreement. That is why a 

simple memorandum of understanding between FERC and the CFTC would be fundamentally inequitable and unworkable. Any such deliberation would seem to inevitably result in the CFTC’s assertion of exclusive jurisdiction over matters which 

have historically been the legitimate purview of FERC. 

To address the concerns I have outlined, we respectfully request the members of 

the Committee to support legislation that: (1) clarifies FERC’s plenary and exclusive 

jurisdiction over products and services provided under a FERC-approved tariff and 

subject to regulatory oversight by the FERC (except for ERGOT, which the legislation should recognize is subject to the Public Utility Commission of Texas’s jurisdiction), and (2) confirms that RTOs and ISOs, and ERCOT, would not be subject to 

CFTC regulation as if they were NYMEX-like futures exchanges or derivatives 

clearing organizations. We would welcome the opportunity to work with the Committee to develop legislation to address our concerns. 

As you have heard from New York Public Service Commission Chairman Garry 

Brown, the National Association of Regulatory Utility Commissioners (NARUC) 

shares our industry’s position on these critical issues. At its meeting in February, 

NARUC expressed its strong support for exclusive FERC jurisdiction over any 

agreement, contract, transaction, product, market mechanism or service offered or 

provided pursuant to a tariff or rate schedule filed and accepted by the FERC, or 

the Public Utility Commission of Texas for Texas/ERCOT.3

We believe that Congress should recognize and preserve FERC’s exclusive jurisdiction. Electric and gas utilities, electricity generators, and renewable energy providers utilize FTRs and OTC derivatives to manage risk with the ultimate aim of 

helping to ensure stable and affordable rates for our customers. We do this by using 

derivatives transactions to hedge against price volatility in natural gas and wholesale electric power—two of the most volatile commodities—that already are substantially regulated. Adding CFTC regulation and costly new requirements to this mix 

will not resolve the issues that Congress wants to address in the wake of the financial crisis, but will serve only to increase energy costs that will ultimately be passed 

on to our customers. CFTC regulation should be left to areas where their expertise 

carries benefits, such as by focusing on the transactions and market participants 

that could yield a systemic risk that would jeopardize our economy or financial system. 

I appreciate the Committee’s invitation to testify today and your willingness to 

examine these issues. I hope that I have provided you with a sense of the impact 

of duplicative regulation of energy transactions and how it would result in higher 

costs for companies like FPL Group, which in turn would result in higher costs for 

our customers. I would be pleased to answer any questions you may have. 

The CHAIRMAN. Thank you very much. 

Mr. Henderson, go right ahead. 
43 

STATEMENT OF MICHAEL W. HENDERSON, VICE PRESIDENT & 

CHIEF FINANCIAL OFFICER, ARKANSAS ELECTRIC COOPERATIVE CORPORATION, ARKANSAS ELECTRIC COOPERATIVES, INC., LITTLE ROCK, AR 

Mr. HENDERSON. Thank you, Mr. Chairman, Ranking Member to 

this committee. I would like to thank you for the opportunity appear this morning. I also would like to take this opportunity to 

thank our home State Senator, Senator Lincoln, as well as the 

chairman and ranking member and other members of the committee that is working together to come up with a global fix for this 

issue. 

I have submitted my written testimony on behalf of the 17 rural 

electric cooperatives of the State of Arkansas who represent 

470,000 consumers in rural Arkansas, as well as another 30,000 

outside the State of Arkansas that are served by the 17 cooperatives, as well as 42 million additional rural electrification consumers. 

For us, this issue is all about cost. Our mission is to keep costs 

as low as possible. That is one of the keys for rural America to be 

able to provide a little economic prosperity for that region. So that 

is our sole purpose for being here today is to try to keep costs as 

low as possible. 

Speaking of costs, the issues of FTRs and CRRs—those really 

originated as a way to balance cost for providing transmission service. So we have used those as an integral part of the cost of service 

of transmission. So we think that should remain in the area of 

FERC that is charged with determining just and reasonable rates. 

We also think that if you take the regulatory authority of those 

and put them into CFTC, that will fractionalize that ratemaking 

ability. So it makes it tougher for one entity to have control over 

determining a cost for all, and again for us, it is providing the lowest cost possible. 

We do think there are some negative aspects of having 2 regulatory authorities. As others have alluded to, there is additional liquidity facilities that could be required. That would be very costly 

to us. 

The arena that we conduct business in under FERC, we know 

most of the parties. The kind of parties we are doing business with 

are like-kind entities. When you pull that market out and interject 

additional financial entities, other commercial entities, those are 

counter-parties we do not necessarily know. Default risk goes up 

for us. So that is an additional cost exposure that we would face. 

We think there are some positives to 2 regulatory authorities, 

though. You know, 2 sets of eyes are always better than one. We 

think greater transparency that others had mentioned is a positive 

attribute. We think greater protection against market manipulation by having that extra set of authority provides benefit. We do 

see a role for CFTC acting more as a judiciary auditor type function, as kind of an overseer but not really a policymaker or a regulatory provider. 

So, in short, what we offer up or request is that status quo relief 

for the FERC regulation remain in place, that we are open and accept the idea of a bright line, you know, making a more clear definition of the different roles. 
44 

That is the comments I have today. So I would take any questions anyone has. 

[The prepared statement of Mr. Henderson follows:] 

PREPARED STATEMENT OF MICHAEL W. HENDERSON, VICE PRESIDENT & CHIEF FINANCIAL OFFICER, ARKANSAS ELECTRIC COOPERATIVE CORPORATION, ARKANSAS

ELECTRIC COOPERATIVES, INC., LITTLE ROCK, AR 

Mr. Chairman and committee members, it is an honor to appear before this committee. Thank you for this opportunity to share the views of the electric cooperatives 

of Arkansas pertaining to regulation of financial transmission rights (‘‘FTR’’), congestion revenue rights (‘‘CRR’’) and other related components of providing electric 

transmission services to our consumer-owners, I would also like to thank our home 

state senator, Senator Blanche Lincoln, who since becoming Chairman of the Agriculture Committee has taken an intense interest in this issue, and we appreciate 

her efforts to craft a common sense global fix to this issue. 

Seventeen Arkansas electric cooperatives provide electric power to approximately 

468,900 consumer-owners in Arkansas, and another 29,229 in adjoining states. Electric cooperatives provide service to 62 percent of the land area, and 74 of the 75 

counties in Arkansas. The electric cooperatives in Arkansas provide service on a notfor-profit basis to some of the poorest service territories in the nation. Nation wide, 

electric cooperatives provide electric power services to approximately 42 million consumer-owners in 47 states. 

Arkansas Electric Cooperative Corporation (‘‘AECC’’) is a generation and transmission cooperative that provides power supply and transmission delivery service to 

the 17 distribution cooperatives in Arkansas. AECC provides transmission service 

to its native load within three separate transmission control areas: Entergy, American Electric Power (‘‘AEP’’) and the Southwestern Power Administration (‘‘SWPA’’), 

an agency of the Department of Energy. AEP and SWPA operate within the Southwest Power Pool (‘‘SPP’’), a regional transmission organization (‘‘RTO’’) under the 

regulation of the Federal Energy Regulatory Commission (‘‘FERC’’). AECC strategically determined it was in its member’s best interest to share in the utilization of 

the transmission systems of Entergy, AEP and SWPA to prevent duplicating infrastructure. Therefore, AECC is a transmission dependent utility relying on fair and 

equitable access to the transmission grid through the SPP RTO. 

Cost pressures on transmission delivery services are constantly increasing. The 

physical cost of AECC providing transmission service to rural Arkansans increased 

60.8 percent from 2004 to 2009. That is a compounded annual increase of 9.97% per 

year. Managing transmission costs is vital to meeting our goal of providing reliable 

electric service at the lowest possible cost, and helping to improve the quality of life 

for rural Arkansans. 

The intention of many of the derivatives regulation reform proposals being proposed in Congress, including the financial reform bill that passed the U.S. House 

of Representatives (H.R. 4173), to protect market participants is certainly laudable. 

In fact, we believe the CFTC should continue to look for market manipulation in 

the bilateral OTC natural gas and power markets. These investigations occur after 

transactions have been made and should not impede the smooth running of FTRs 

and CRRs. However, we feel that derivatives regulation proposals should respect the 

fact that the inclusion of RTO FTRs and CRRs, which are more closely attached 

with the physical service reliability requirements of providing electricity, is not appropriate as they do not fit the characteristics of other commodities for which legislative proposals would regulate. We are concerned that proposed legislation could 

inadvertently make it difficult and more expensive for AECC to deliver power in an 

RTO market. 

Most RTOs operate both a real-time and day-ahead market for electric power. 

These markets establish locational marginal prices (‘‘LMPs’’) for energy based on the 

bid price of the last unit dispatched to meet load in the RTO region. The level of 

congestion in different parts of the transmission system can change hourly; therefore, the cost of power generated and consumed in different parts of the system can 

vary greatly and is extremely volatile. That volatility is challenging for utilities because the LMPs not only establish the cost of power for utilities buying energy out 

of the market or selling energy into the market at any particular location, the LMPs 

also establish the cost for utilities that generate with their own power resources to 

deliver that power to their consumers. Utilities are paid the LMP price for energy 

they generate at one point of the system, and simultaneously pay the LMP price 

for energy at the point where it is withdrawn to serve their consumers. Thus any 

difference in the LMP between the ‘‘source’’ of the power, and the ‘‘load sink’’, 
45 

change the cost of delivered power due to congestion incurred for delivering through 

the RTO-managed transmission system. Congestion costs for a utility are determined by a positive difference between the cost paid to serve their load at a location 

minus the revenue received for power generated at a different location. 

In order to help utilities hedge congestion cost risk, the FERC requires RTOs that 

operate real-time and day-ahead LMP markets, to make FTRs or CRRs available 

to market participants. By virtue of payments for physically firm network transmission service, load serving entities like AECC are annually allocated certain financial revenue rights by the RTO in order obtain FTRs or CRRs. FTRs and CRRs 

are monthly, annual or other periodic financial instruments that entitle holders to 

congestion revenues along a particular transmission path. These FTR and CRR revenues help offset the costs incurred by utilities to deliver energy over the congested 

transmission paths. As load profiles change and sources of supply change over time, 

these unbundled financial instruments can be bought and sold to align a market 

participant’s congestion protection with the ever changing congestion exposure that 

results from the need to use frequently changing transmission paths. Consequently, 

FTRs and CRRs were created to help market participants maintain balance over 

time between the financial costs of providing transmission service with the requirements of providing physically reliable transmission service in a constrained and congested transmission system. 

As previously discussed, AECC participates in the SPP RTO. The SPP is currently 

evaluating and designing how it will develop the FTR or CRR market for its area 

of responsibility. Other RTOs such as the RIM and Midwest Independent System 

Operator (MISO) already operate congestion rights markets. Even though the FTRs 

and CRRs have been separated from the physical cost of delivery, they remain an 

integral part of the overall cost of service. 

The electric cooperatives of Arkansas and cooperatives across the country are concerned that proposed legislation would place regulation of FTRs and CRRs under 

the regulatory oversight of the Commodities Futures Trading Commission (CFTC). 

Oversight by the CFTC would fragment load serving entities’ ability to manage their 

transmission costs. The FERC comprehensively regulates all jurisdictional wholesale 

sales and jurisdictional interstate transmission service, pursuant to the Federal 

Power Act, as an integral part of the overall electric market structure. Sections 205 

and 206 of the Federal Power Act give FERC authority to ensure that the rates, 

terms and conditions of all jurisdictional wholesale sales of power and all jurisdictional transmission service in interstate commerce are just and reasonable. In order 

to fulfill that duty, FERC has required RTOs to file tariffs at FERC governing every 

aspect of their markets. The design, operation and governance of RTOs financial 

rights, and the obligations of parties who participate in the markets, and the means 

which the RTOs monitor the markets for market power and market manipulation, 

are all filed at FERC, and bought and sold pursuant to FERC filed tariffs. Mismanagement of the markets by the RTOs and misconduct in those markets by participants are both subject to penalties from FERC. An exception to this FERC regulation is in Texas. In the State of Texas a single grid operator called the Energy 

Reliability Council of Texas (ERCOT) operates a day ahead and real time market 

and administers CRR’s to hedge congestions. The ERCOT is overseen by the Public 

Utility Commission of Texas (PUCT) who serves the single regulator for commercial 

power and transmission markets in Texas. 

AECC believes keeping all components of transmission costs regulated by a single 

entity will ensure lower overall cost for its members. If the FTR and CRR markets 

are allowed to be regulated by an entity outside of the FERC (or PUCT in Texas), 

market participants could be forced to maintain multiple backup credit facilities 

(credit facility for FERC physical transactions and credit facilities for FTR/CRR 

market). A weakened economy and constrained capital resources at financial institutions are already resulting in higher cost credit support facilities. Another factor to 

consider is that market participants in a FERC regulated market are mostly entities 

of the utility sector serving end-use load. The credit risk for utility market participants is generally less than a market that has a higher concentration of counterparties that trade speculatively. One way to eliminate and avoid counterparty risk is 

to force participants to provide cash collateral sufficient to cover the full exposure 

of all trades executed. But this option increases cost to end-use utility consumers 

and idles large amounts of cash making it more difficult for utilities to maintain 

capital expenditures on infrastructure to provide reliable electric service. 

In conclusion, on behalf of 468,900 electric cooperative consumers in Arkansas 

and approximately 42 million electric cooperative consumers throughout the nation, 

the electric cooperatives believe it is in the best interest of utility consumers to ensure regulation of FTRs and CRRs remain under the regulatory authority of the 

FERC and the PUCT in Texas. RTO markets and RTO-created products are integral 
46 

to the RTOs regulatory reliability mission. FERC and the PUCT should also maintain jurisdiction over physical forward transactions, whether or not those transactions ultimately result in physical forward delivery or are booked out. There are 

other energy hedging products that are available for use by the general public. 

These are appropriately regulated by the CFTC but the FTR and CRR markets 

should remain under the oversight of the FERC or PUCT in Texas. In my opinion, 

the global fix prescribed by Senator Lincoln could help keep the cost of providing 

electricity to Arkansas consumers as well as electric consumers across the nation 

lower. 

Mr. Chairman, thank you for the opportunity to share our concerns with you and 

the Committee on Energy and Natural Resources. 

The CHAIRMAN. Thank you very much. 

Why do we not find a couple of other chairs and ask Chairman 

Wellinghoff and Chairman Gensler to please come to the table. The 

rest of you stay at the witness table too, and we will do some questions here as long as we are able to. I think we can get all 6 folks 

there. Good. 

I will start with a question to Chairman Wellinghoff and just 

ask, reference has been made to this provision in H.R. 4173 that 

directs FERC and the CFTC to develop a memorandum of understanding to establish procedures, to share information, and avoid 

conflicting and duplicative regulation by the 2 agencies. To what 

extent do you think this helps? This is a resolution of the concern 

and Congress should basically allow that provision to solve the 

problem. 

Mr. WELLINGHOFF. Mr. Chairman, I basically agree with Chairman Kelliher that Congress does need to solve the problem with respect to jurisdiction. 

I think certainly we can enter into a memorandum of understanding with the CFTC and would like to do so regarding our respective investigatory powers and the ability to get information 

from markets that we each regulate so that we can establish and 

preserve our regulatory authority to ensure that there is no fraud 

and manipulation in the markets. The CFTC certainly may need 

information from some of the markets that we oversee and vice 

versa, and I think that kind of sharing and cooperation is necessary, but I do not see personally a memorandum of understanding with respect to the issue of jurisdiction. I really think that 

is something that Congress needs to do with a bright line. 

Mr. GENSLER. If I might. 

The CHAIRMAN. Yes, go ahead. 

Mr. GENSLER. What the House of Representatives included in the 

various agreement between Chairman Waxman and Chairman 

Peterson that worked through that actually went well beyond a 

memorandum of understanding, and I would be supportive of going 

beyond that. It had a very explicit savings clause for the good work 

that this committee and Congress did in that anti-manipulation 

area, the EPAct rules of 2005. It had other various savings clauses 

for FERC jurisdiction with regard to regulation of electricity and 

natural gas under their tariffs. It had some savings clauses, of 

course, for the CFTC as well. 

Then it actually directed that we use our 4(c) exemptive authority. Under the 1992 provisions, we can, without determining 

whether something is a future or not, actually exempt various activities. 
47 

So I think it was actually far more than what Chairman Kelliher 

was talking about. There was a lot more, and working with this 

committee, I think we can sort this through and working with this 

relationship, I think we can. 

The CHAIRMAN. It does seem unusual, though, for Congress to 

say that you can decide what is exempt rather than Congress deciding what is exempt. Am I confused about that? 

Mr. GENSLER. I think what it is we as an agency are overseeing 

markets to ensure they are fair and orderly, these derivative marketplaces. The FERC has very important jurisdiction and mission 

as well. So we coexist, as we coexist with the Department of Agriculture, we coexist with the Department of the Treasury. Treasury 

issues physical Treasury securities. We oversee futures of Treasuries. We currently oversee natural gas and electricity futures that 

trade on NYMEX. I do not think this committee wants to take that 

away from the CFTC, but if you want to give it to FERC, you 

know, the Congress can do that. So it is a coexisting between missions going forward. 

The CHAIRMAN. Let me ask on this specific that Joseph Kelliher 

talked about there, the auction that occurred, the PJM auction I 

gather, in New Jersey last month. What is your thinking about the 

role the CFTC would play on that kind of a—— 

Mr. GENSLER. I am glad you asked it. I understand the facts on 

that, probably none. I think it is a red herring, with all respect to 

Chairman Kelliher. I think it is probably a cash transaction that 

is excluded under the Commodity Exchange Act. We do not cover 

cash or physical spot or forward contracts. 

If Congress were to move forward and actually suggest that we 

cover broad, over-the-counter derivatives, it would only be the 

standard transactions that would be recommended to be brought to 

central clearing, and I think the transaction he was describing, if 

it were an over-the-counter derivative, would actually be customized or tailored. 

We do think there are 2 debates here, as many of the panelists 

said. There is a debate of a little jurisdictional thing here between 

the FERC and the CFTC, which I think we can sort through with 

the good help of the committee. There is this end-user question, 

which I have taken a public policy perspective. I think we lower 

risk to the American public by having all of these transactions that 

are standard in clearinghouses, but if you exempt the energy transactions, I would just ask Congress not to exempt all the financial 

transactions. 

The CHAIRMAN. But the idea of having an energy end-user exemption, which has been suggested by several, is something that 

you think might make sense? 

Mr. GENSLER. No. I am actually very much publicly on the record 

saying that I think that if it is a standard transaction, it would be 

best to be brought into central clearing and central trading. I understand the votes probably are not there for that, sir. So if there 

is an exemption for central clearing for end-users in the energy 

market, I think that should not sweep an end-user for trading. 

Transparency is unarguably a good thing. You could have them required to be transparent and still allow them to be bilateral and 

not be centrally cleared. 
48 

The CHAIRMAN. Let me ask Chairman Kelliher if he had any 

comment on that. 

Mr. KELLIHER. I do not think the example in the testimony was 

a red herring. I think it did involve standard products that would 

be forced to clear on the exchange, but I can submit more information for the record of the hearing. 

The CHAIRMAN. I think that is a useful example for us to try to 

understand how these different policies would be affected there. 

Senator Murkowski. 

Senator MURKOWSKI. Thank you, Mr. Chairman. 

I am trying to determine whether or not we really do have a regulatory gap. Mr. Kelliher, you mentioned that you do not believe 

that one exists. You said there is no loophole to close. There is no 

regulatory gap to plug. I would ask the question both to you, Chairman Wellinghoff and Chairman Gensler, do we have a regulatory 

gap here or is Mr. Kelliher correct in that the FTRs are already 

regulated by FERC through its review and its approval of the RTO 

tariffs. 

Mr. WELLINGHOFF. Ranking Member Murkowski, thank you for 

the question. 

I believe there is no regulatory gap whatsoever. We do fully and 

completely regulate the FTRs. 

To the question of the issue of what would be swept in under the 

CFTC’s authority, if they take in the FTRs, as I understand it, that 

ultimately would sweep in the whole market because ultimately 

they would require the RTO market, in essence, to be a clearing 

market under their regulations. So I think Chairman Kelliher is 

correct in his New Jersey example as well, and again, it is one step 

that would move us to a place that I think we do not need to go. 

We do not need an exemption because, in fact, there is nothing 

to exempt. We, in fact, fully regulate this area already, the FTRs. 

So I see no loopholes at all. 

I would also add that I do not believe that creating bright lines 

creates loopholes. I cannot see that connection. 

Mr. GENSLER. We probably have a little bit different perspective 

on this. I do think that bright lines in this area could have the unintended consequences because markets evolve and change, and it 

goes to the Senator’s question about these financial transmission 

rights. We at the CFTC have not taken a public position as to 

whether they come under the Commodity Exchange Act. In essence, the right question is are they futures. 

But I think that the FERC does take the leadership here and 

should continue to take the leadership here, but we do not know 

how this contract or this market may evolve. I do not even think 

PJM might know how they might evolve. 

Congress has asked that one agency, the CFTC, have broad and 

uniform jurisdiction, exclusive jurisdiction, on derivative contracts. 

We can use the exemptive authority to stand down, to stand back 

when it is ambiguous, and sometimes it is not clear and FTR is an 

example where it has begun to be not clear, but where we are just 

giving some advice, for instance. Jon and I have had a good relationship about this around this risk management situation. I am 

glad to have the FERC taking the lead, but we do not know this 

ambiguity will evolve over time. 
49 

Senator MURKOWSKI. Let’s discuss that further, Chairman 

Gensler, both Mr. Kelliher and Mr. Wellinghoff indicated that in 

their opinion the energy providers do not pose this systemic risk 

to the broader economy. As we are looking to address financial reform regulation, that is a different area. Would you agree with 

them that within the energy market with those energy providers, 

they do not pose that systemic risk? 

Mr. GENSLER. I think that the financial system so terribly failed 

the American public, and part of that is this over-the-counter derivatives world. So I believe that we need to be in greater transparency, and we can do that on the standard transactions. I think 

that is actually a positive to the consumers that FERC protects if 

we brought the standard transactions into transparent trading 

venues. I am not talking about the FTRs. I am talking about overthe-counter derivatives. 

Senator MURKOWSKI. You do not think that the FTRs that are 

traded through the RTOs are standardized? 

Mr. GENSLER. I do not know the answer to how they will evolve, 

and the commission has not taken a view as to whether they are 

futures under the Commodity Exchange Act. But I think that the 

broad market, whether it is natural gas derivative where somebody 

is just hedging a natural gas risk, could be standardized. 

Having said that, many are customized. Many are tailored and 

should remain tailored. Corporations—the very good testimony 

from Mr. Henderson. They need to be able to tailor and hedge their 

risk. Garry Brown’s testimony. I believe they need to be able to tailor and hedge their risks. But we also want to protect the public 

and lower risk and add transparency. 

Senator MURKOWSKI. Mr. Brown, you spoke to the expense to the 

consumer. Are we able to quantify what those expenses may be, or 

at this stage, is it relatively hypothetical in terms of what the consumer might anticipate? 

Mr. BROWN. It is somewhat hypothetical in the sense that we are 

not quite sure, as this panel indicates, which products in the end 

would be covered by this. But the numbers that we hear on a nationwide basis is that it could require utilities to put up billions in 

additional collateral, and that is money that would then be taken 

from all the other things that utilities need to do, building infrastructure, promoting renewables, all the other things we have got 

the utilities doing right now. 

We used a key phrase in our testimony. We should compare the 

costs of this with the benefits. I cannot disagree with Mr. Gensler 

that there are potential benefits, but the question is, is it worth the 

potentially billions of dollars of costs? Is there any evidence that 

indicates we really need to require that at this point in time? I 

think our viewpoint there is no jurisdictional gap. We have got the 

Federal Energy Regulatory Commission, and we would prefer to 

keep our State/Federal arguments focused on Commissioner 

Wellinghoff’s agency rather than have a jurisdictional confusion 

about who is overseeing what. 

Senator MURKOWSKI. Thank you, Mr. Chairman. 

The CHAIRMAN. Senator Lincoln. 

Senator LINCOLN. Thank you, Mr. Chairman. 
50 

The CHAIRMAN. Who I should point out, of course, is chair of the 

committee with primary jurisdiction over the CFTC. So she has a 

vital interest in this. 

Senator LINCOLN. Thank you, Mr. Chairman. I do so appreciate 

you and Senator Murkowski holding the hearing today. As you 

mentioned, we do share an interest in this very complex issue and 

certainly look forward to working with both of you all as we move 

forward in solving some of these problems and, as Chairman 

Gensler mentioned, putting our economy back on track and providing confidence in the marketplace as we do so. 

I do want to also take the opportunity to thank my constituent, 

Michael Henderson, for coming up from Little Rock today to provide his testimony. Michael is the VP and CFO of Arkansas Electric Cooperatives and the coops do provide a critical service to the 

people of our State. I want to thank you, Michael, and all of the 

folks at the coops in Arkansas for what you all do. We are grateful 

and we are grateful for your comments about looking out for our 

consumers, particularly those in rural America. 

Mr. Chairman, I am particularly interested in finding a path forward that does respect the missions and the expertise of both of 

these agencies, the CFTC and the FERC. I have stated publicly 

that these agencies and our committees can draft that compromise. 

I feel very confident. We may have to leave for a vote, but we certainly want to make sure that all of you all are committed to continue to sit around the table and figure out what that compromise 

needs to be and can be. 

But I also remember the words of Robert Frost which said ‘‘good 

fences make good neighbors.’’ Being a farmer’s daughter and understanding when someone’s cows get into your wheat crop, it is not 

a good thing. You want to make sure that with good fences, you 

do produce good neighbors, and I think as hard as Chairman 

Gensler and Chairman Wellinghoff work together, it is critical for 

them to have a clear understanding from us in terms of what our 

intentions are, that there are no regulatory ambiguities, I believe 

is what Mr. Brown mentioned earlier. I think that is really important. 

I do see a compromise where FERC would get clear control of the 

regional transmission organizations. RTOs are clearly in their jurisdiction and the existing final products that are used. The CFTC 

would continue to exercise exclusive control of the New York Mercantile Exchange and the Intercontinental Exchange, as well as energy futures and swaps. 

Nothing would prevent one agency from notifying the other of 

concerns. You are already working together, and I think that is important. Concerns that you may have—hopefully, you will notify 

one another, which would help assist in enforcement. This is common sense, and I think it is just and equitable results of what we 

are trying look for. 

I would say, as we converse and talk about gaps, it is not as 

much gaps in regulation as it is overlap. Any of that ambiguity 

that may exist we in Congress I think have a responsibility to put 

clarity to, and I hope that we will. I think in these economic times, 

no one wants duplicative regulation. We want to put our economy 

back on track. We want to provide confidence to consumers and 
51 

make sure that folks can turn their lights on and still afford it. 

There is no doubt that all of those things are our objectives. 

So I want to thank the NRECA and the EEI, the EPSA for their 

willingness to work with me certainly and others, I think, on a 

global fix. Mr. Henderson mentioned a global fix. I hope that is the 

objective we can set before us and come together in coming up with 

what we need to do there. 

I just would leave these couple of questions with you. Chairman 

Wellinghoff, you know the New York Mercantile Exchange is currently registered and regulated by CFTC. NYMEX was founded in 

the 1870s I think. Do you think that the FERC should be regulating futures contracts on NYMEX? 

Mr. WELLINGHOFF. No, absolutely not. We only have an interest 

to the extent that we may need information with respect to activities in that exchange, and we certainly have a cooperative agreement with the CFTC do do that and require that information to the 

extent that it may somehow impact a physical market and the manipulation or fraud that may be going on and we may be investigating that physical market. But we certainly have no interest in 

regulating it. 

Senator LINCOLN. To that end, Chairman Gensler, you know 

PJM is a regional transmission organization which was created by 

and overseen by FERC. As I understand it, PJM started operating 

I think in 1999, 11 years ago. Do you think the CFTC should be 

regulating PJM, its products or its participants? 

Mr. GENSLER. Chairman? Can I call her chairman? She is my 

chairman. Chairman Lincoln, there is a possibility in the future it 

would. It depends how markets evolve. I think that FERC take the 

leadership over RTOs. Most, probably 99 or 98 percent, of the products have no implication whatsoever in the derivatives marketplace. But I do think that Congress, in giving exclusive jurisdiction 

to one agency to oversee derivatives, whether they be futures products or not, gives some uniformity and consistency. So I cannot predict how this small market might evolve or mutate in the future, 

and I am concerned about bright line tests and I have sort of got 

some scars on my own back from the Enron loophole and the experiences we had there. 

Senator LINCOLN. But you are basically talking about what 

might be a futures in the future, or you are talking about a product 

that may evolve out of what transpires with PJM perhaps in terms 

of its products—— 

Mr. GENSLER. I think that is right, and to the extent that there 

is a centralized marketplace where buyers and sellers meet over 

derivatives contracts, I think Congress does want one agency. You 

know, I will go and the career staff will go, but I mean, to have 

one agency to do that and coexist with other agencies that oversee 

the physical markets, as we do with the Department of Agriculture 

that, of course, you know so well. 

Senator LINCOLN. I appreciate that. 

As you both know, I have suggested this global fix or coming to 

find a global fix, a concept to resolve these jurisdictional disputes 

between FERC and CFTC. I think several industry groups have expressed a willingness to work together to come up with whatever 
52 

this fix needs to be. Would your agencies be willing to work with 

us on a solution of that type? 

Mr. GENSLER. We are always willing to work with all members, 

but certainly the chairman. 

[Laughter.] 

Senator LINCOLN. The other gentleman is going to be at the table 

too, and I look forward to working with him and his staff and others. But I do believe that particularly in this day and age with the 

economic circumstances we find ourselves in, that the duplicative 

regulation is just not appropriate, and I do believe that we have 

got to be able to determine and figure out where that overlap exists 

and what problems it is causing and make sure that we get you 

2 gentlemen—— 

Mr. GENSLER. I would certainly hope that we would continue our 

very good relationship and in trying to avoid some duplication, as 

you say, that we do not create the gap line, the fault line because 

it really does evolve. These markets, all markets evolve so much, 

and that is one of the hard lessons I have had to take from this 

financial crisis, that markets that we did not look at, credit default 

swaps where you had a blip on the radar screen or electronic trading, and then we end up with an Enron loophole and a swaps loophole. Certainly looking back now, I think what could we have done 

differently and I was part of that. 

Senator LINCOLN. I do not disagree that there are very few 

Americans out there that would argue that over the past 15 to 20 

years, there has been a tremendous evolution of financial instruments out there, and as they have evolved—you are exactly right— 

their markets have. The only way that we have known what our 

problem has been is looking in that rear view mirror to see what 

that $400 trillion marketplace was. We do not want to keep looking 

in the rear view mirror. We want to look forward and we want to 

have, without a doubt, you all in the capacity that you need to be 

to have that transparency, the oversight that is necessary to ensure 

that as we move forward, that we are not dealing with the kind 

of issues and the kind of things that were happening that no one 

knew about. So we will look forward to working with you. 

Mr. Chairman, I certainly look forward to working with you. I 

have never found a more thorough or dedicated member of the body 

that does not get down to the details—the devil in the details as 

Mr. Chairman Bingaman does. So I appreciate it. Thank you. 

The CHAIRMAN. Thank you very much. 

Let me just ask Mr. Duane going back to this example of the auction that occurred. PJM had the auction last month we were advised. Could you describe that? Are these standardized, this RTO? 

Are these customized? What was the circumstance there? 

Mr. DUANE. I would have to coordinate with former Chairman 

Kelliher to exactly understand his example, but I think his point 

is a valid point. 

PJM runs auctions in our energy markets and we run auctions 

in our FTR markets and capacity markets. These products are very 

specific. For instance, on the FTRs, there are literally tens of thousands of combinations that could constitute an FTR. 

We, in running those auctions, have from time to time been in 

discussions with third party clearing organizations as to whether 
53 

they would be interested in providing the sorts of clearing services 

that Chairman Gensler might like to see in those markets, and not 

only is it cost prohibitive, but they are really unable to provide the 

services given the unique attributes of this product that is really 

not a financial product. It is, as we have discussed, tied to the financial transmission service. 

So somewhat ironically we are having a lot of discussion about 

something conceptually that even if we were to try and mandate 

the clearing of these FTR products out of these auctions, I am not 

sure it could even happen, which causes me concern and it causes 

our market participants concern that the product may just die and 

go away, exposing customers to the very volatile prices that are attendant to the electricity commodity. 

The CHAIRMAN. What I am understanding—and I may be very 

confused here, but what I am understanding the House legislation 

to provide is that the CFTC would be given authority to make a 

determination that PJM is a designated clearing organization, and 

if they did that, then presumably that would cause a whole new 

set of requirements to be put in place. Is that wrong, Chairman 

Gensler? 

Mr. GENSLER. Actually we have that clear authority right now. 

The CHAIRMAN. Oh, you do. 

Mr. GENSLER. Yes. We have that clear authority right now. 

The CHAIRMAN. What do you think the House—with regard to 

PJM, what do you believe the House legislation allows you to do 

that you currently cannot do? 

Mr. GENSLER. What the House legislation does is it sets up a 

clear number of savings clauses for FERC and then sort of directs 

us to look at our exemptive authority. We have not had—under the 

exemptive authority, somebody would have to come and actually 

file—it is a formal filing to do that exemption, and then we would 

go through it. If somebody did that on these financial transmission 

rights, we would dispatch with it. You know, a number of months 

it takes to dispatch with it. We would probably work closely with 

Chairman Wellinghoff as well. 

But under the Commodity Exchange Act right now, we can do 

this. 

The CHAIRMAN. So you do not believe the House legislation gives 

you any additional authority that you do not currently have over 

PJM? 

Mr. GENSLER. The House legislation is a broad and very important legislation about over-the-counter derivatives, but that discussion is really well—I think Mr. Duane would probably agree—different and removed in a sense from the PJM discussion. 

The CHAIRMAN. So you do not think the language of the House 

bill contemplates regulation by the CFTC of PJM or similar organizations. 

Mr. GENSLER. I think it contemplates that we work closely with 

FERC. Frankly, I think it is with FERC taking the lead on any of 

this. As Chairman Wellinghoff has, I think, artfully said, they have 

a whole unified approach to this regulation. 

But to the extent that any entity—it could be a nonfinancial company in America—any entity starts to have some centralized market, centralized derivatives markets and so forth, then a deriva-
54 

tives regulator could get involved. That is the CFTC. I think that 

is where the uncertainty or ambiguity might be for PJM. 

But under the Commodity Exchange Act right now if, as you say, 

something was a clearing organization, we have authorities there 

already. 

The CHAIRMAN. Mr. Kelliher, did you have a point of view on 

that? 

Mr. KELLIHER. The House bill is complicated to read because you 

have to read a couple different sections—you asked me. Did you 

ask Chairman Wellinghoff or me? 

The CHAIRMAN. No, I meant you and then I am glad to hear from 

Chairman Wellinghoff, too. 

Mr. KELLIHER. Page 589 of the House bill has a section that to 

me suggests some authority is transferred to the CFTC. This is the 

exemption section I think Chairman Gensler is referring to. But it 

talks about how the CFTC may exempt from its regulation agreements, contracts, or transactions that are entered into pursuant to 

a FERC tariff if CFTC determines that the exemption will be consistent with the public interest and CFTC cannot unreasonably 

deny any request by FERC for such exemption. So to me that suggests that the default is some level of FERC regulation shifts to the 

CFTC unless the CFTC decides otherwise. It is really the combination of—the MOU provision and this section in tandem I think suggest there is a change. 

The CHAIRMAN. Chairman Wellinghoff, did you have a point of 

view there? 

Mr. WELLINGHOFF. I do not think the House bill—well, I think 

this disagreement of jurisdiction predated the House bill, first of 

all. We saw the House bill as a vehicle perhaps for us to set a 

bright line and we went in with that discussion. The House chose 

not to do that, but instead created this MOU construct that quite 

frankly I think leaves it primarily to the CFTC under their current 

authority to determine whether there is an exemption. We believe 

there should be a bright line like Senator Lincoln. I think that the 

Congress needs to set a line. The RTOs and things under FERC’s 

tariff are within our jurisdiction and NYMEX, ICE, and other 

things are within the CFTC’s jurisdiction. So that is really what we 

were hoping for. We did not get that out of the House bill. But we 

hope to be able to work with you and with Chairman Gensler to 

move forward on that. 

The CHAIRMAN. Chairman Kelliher, did you have another—— 

Mr. KELLIHER. I will make just one small comment on how the 

jurisdictional disagreement between the agencies started. It really 

started a few years ago when FERC was implementing the antimanipulation provisions of the Energy Policy Act that you took the 

lead on, and trying to faithfully follow the intent of the committee 

and Congress, you used certain terms that suggested FERC’s authority to police manipulation is much broader than its authority 

to set rates. So FERC, interpreting that, thought manipulation in 

the futures market that affects FERC jurisdictional markets is 

something Congress wanted FERC to police. 

CFTC, I cannot say unreasonably—if I were the CFTC Chairman, I would have thought, wait a minute. That is intruding into 

our jurisdiction. We have exclusive jurisdiction in certain areas. So 
55 

there immediately was a disagreement between the agencies that 

has persisted and I think is aggravated by the House bill. But I 

think it is an honest disagreement, but at this point I think it is 

immutable. It has been in the courts. 

Mr. GENSLER. Yet, if I might to the tchairmen on my right, the 

CFTC and FERC work cooperatively on this. It was that Amaranth 

case, a joint investigation. We filed the cases a day apart and ultimately had some joint settlement. So there is a lot of actually— 

even in that case—really working together. 

Now, the defendant filed in the court and asked for this jurisdictional thing. But my predecessors at the CFTC were really sort of 

working jointly, I guess, with Mr. Chairman Kelliher at the time. 

Mr. KELLIHER. I agree. The 2 agencies have actually worked very 

well to exercise their enforcement authorities, notwithstanding the 

disagreement. 

The CHAIRMAN. As I indicated before, we have now started 4 

votes on the Senate floor. So I appreciate everybody being here. I 

think this has been useful testimony. I thank everyone for coming 

and we will try to come to a resolution. Thank you. 

[Whereupon, at 11:14 a.m., the hearing was adjourned.] 

(57) 

APPENDIXES 

APPENDIX I 

Responses to Additional Questions 

RESPONSES OF GARRY BROWN TO QUESTIONS FROM SENATOR BINGAMAN

Question 1. What would CFTC jurisdiction over FTRs (or any other RTO/ISO 

product) mean for the ratepayers of the state of New York? 

Answer. FERC has presided over the design and implementation of these markets 

and has therefore developed an understanding of them. The full potential ramifications of CFTC jurisdiction over such markets is unclear and such uncertainty can 

negatively impact market confidence and liquidity and thereby damage the markets. 

Any increase in costs due to imposition of CFTC oversight is likely to impact all 

resources such that the increased costs would become a straight pass-through to 

consumers; the net impact is likely to be a tax on ratepayers. 

But, we can construe a scenario where, under certain conditions, it might be possible that if FERC and CFTC had joint enforcement jurisdiction with FERC maintaining the primary authority over FTRs, benefits to ratepayers may accrue. This 

situation could be similar to FERC’s authority over the installed capacity market 

where FERC establishes the rules and regulations but DOJ also reviews the antitrust implications of secondary transactions associated with those markets. 

Question 2. What value do you believe FTRs provide to New York ratepayers? 

How would CFTC regulation of FTR markets alter that value proposition? 

Answer. In New York, FTRs provide benefits to ratepayers by allowing their service providers to hedge congestions costs and reduce price volatility, and also benefit 

ratepayers in that revenues from the sale of FTRs are credited to ratepayers in the 

delivery portion of their bills. If the move to primary CFTC jurisdiction negatively 

impacts market confidence and/or liquidity, the result would be lower FTR sale 

prices and hence a smaller credit to ratepayer bills. As I noted above, however, 

under certain conditions joint enforcement jurisdiction may be beneficial. 

RESPONSES OF GARRY BROWN TO QUESTIONS FROM SENATOR MURKOWSKI

Question 1. Is there currently a regulatory gap we’re trying to plug for electric 

market mechanisms like Financial Transmission Rights? Aren’t FTRs already regulated by FERC through its review and approval of RTO tariffs? 

Answer. FTRs are currently regulated by FERC. However, secondary market trading of FTRs is not presently policed by FERC and such trading can raise concerns 

with regard to gaming of the markets. FERC is currently posing questions regard 

their review of secondary FTR markets in a rulemaking proceeding (RM10-12). 

Question 2. Why can’t utilities clear their derivative transactions on exchanges 

like other standardized commodities? 

Answer. As my testimony points out, the concern is that doing so could raise costs 

to consumers. If a company trades on an exchange, it must meet collateral requirements, and the costs of those collateral requirements including transactional costs 

will ultimately be passed on to the consumer. Alternatively, if a company determines that these costs are too high (making the instrument or transaction not cost 

effective), then the consumer suffers the price volatility risks of unhedged transactions. 

Question 3. Does NARUC support an outright exemption for both wholesale and 

retail market participants? 

Answer. Yes. We support an exemption for those entities that rely on OTC products and markets to manage price risks for legitimate business purposes including 

utilities, suppliers, and customers. 
58 

RESPONSE OF GARRY BROWN TO QUESTION FROM SENATOR STABENOW

Question 1. Please share your views on whether the mandatory reporting of energy commodity contracts to regulated swap or derivative repositories is a regulatory solution that would meet the public policy goals of increasing market transparency, mitigating systemic risk, and providing price transparency, without hindering the ability for end-users to hedge their commercial risk or increasing costs 

to consumers. 

Answer. As was discussed on page 5 of my written testimony, we do believe that 

such reporting would provide sufficient market transparency without the costs associated with mandatory clearing. 

RESPONSES OF VINCENT P. DUANE TO QUESTIONS FROM SENATOR BINGAMAN

Question 1. Could you describe the ways in which utilities as well as other market 

participants come to own FTRs? 

Answer. As a regional transmission organization (RTO), PJM serves as a transmission provider, obligated under the Federal Energy Regulatory Commission’s 

(FERC) regulations, to provide open access, non-discriminatory transmission service 

to customers seeking such service within PJM’s footprint. One type of transmission 

service that PJM is required to offer, again pursuant to FERC directive, is firm 

transmission service. Although some customers purchase transmission service to export power from PJM into neighboring regions, overwhelmingly, customers who purchase firm transmission service (either network or point-to-point) do so to meet the 

needs of the end-use consumers or retail customers that they serve. Firm service 

allows transmission customers, (public utilities, municipal utilities, cooperative utilities and competitive retail suppliers) to move electricity from one point on the system (typically a generation station or hub) to another point (typically a load bus) 

on a ‘‘firm’’ basis, which is to say without further cost beyond the transmission 

charges they pay to PJM for firm service. 

In organized wholesale electricity markets, such as the one administered by PJM, 

prices can differ by location at various points on the system. These differences result 

from transmission constraints, limiting the volume of electricity that can be moved 

reliably across the system. When such constraints exist, PJM, as the system operator, must re-dispatch higher cost generation behind the constraint. The higher cost 

that results behind the constraint is referred to as congestion cost. In order to provide ‘‘firm’’ service as mandated by FERC, and in order to recognize the native load 

rights of those customers that historically have paid for the transmission grid, PJM 

provides firm transmission customers with a mechanism to protect against congestion costs. This mechanism is the FTR. 

FTRs are made available to firm transmission customers as a means to hedge 

against congestion charges. The amount of FTRs is finite; it is limited by the physical capability of the transmission system and calculated using a complex algorithmic model that PJM refers to as a ‘‘simultaneous feasibility analysis.’’ Every 12 

months, PJM will conduct a simultaneous feasibility analysis to determine the level 

of FTRs that can be allocated over the next 12 month period (or planning period). 

Wholesale customers may choose to hold their FTRs or sell them to other market 

participants, which may include other transmission customers, generators, or trading firms (including financial institutions). Thus, the FTR Auctions permit other 

market participants to bid for and acquire specific FTRs and provides a marketbased method to determine the value of those FTRs. In this case, while the economic 

value of the FTR, which is to say the price realized by that FTR in an auction, will 

inure to the customer who originally received the allocation from PJM, the ultimate 

holder of the FTR (depending on auction outcomes) might be a different entity—potentially another load serving utility, or other type of market participant, including 

a financial institution. 

In summary, the value of all FTRs inures to those transmission customers who 

pay in rates for the fixed costs of the transmission service (firm transmission customers) in recognition of their historic payments for the cost of building out and 

maintaining the grid that serves them. This is true whether the transmission customer continues to hold the FTR or whether it receives the realized price of the FTR 

in an FTR Auction (its auction revenue rights). The auction allows transmission customers to buy and sell FTRs to obtain a particular portfolio of FTRs to best hedge 

their particular congestion exposures. It also efficiently allows for an FTR to be held 

by the entity that places the greatest value on it (i.e., the one who bids highest for 

it in the auction). Finally, FTR holders are free to bilaterally contract to sell their 

FTR to another party outside the auction environment. Such bilateral transfers are 
59 

reported to PJM and are subject to particular rules addressing the creditworthiness 

of the transferee. 

Question 2. Would CFTC jurisdiction over FTRs (or any other RTO product) compromise open access to the PJM transmission system for market participants? If yes, 

how? 

Answer. Yes. As described above, the FTR is the means by which those RTOs administering locationally priced markets provide firm transmission service to their 

load serving customers, consistent with FERC Order No. 888 open access mandates. 

To treat the FTR as a CFTC-regulated ‘‘swap’’ or ‘‘futures contract’’ would impose 

on RTOs requirements relating to the trading, settlement and credit risk management of the product that could radically alter the FTR in a manner which would 

frustrate its fundamental purpose—namely to provide a means for wholesale customers to serve their native load at a predictable price consistent with the concepts 

of ‘‘firm’’ transmission service—frustrating the RTO in its mission as a FERC regulated transmission provider and wholesale electric market administrator. 

Open access could revert to a system of physically firm transmission service with 

re-dispatch costs indiscriminately socialized across all users of the transmission system and a greater reliance on physically curtailing or interrupting transmission 

schedules. The efficiencies, greater use and optimization of a transmission system 

brought about by applying market-oriented tools (such as locational pricing and 

FTRs) to provide ‘‘financially firm’’ open access is well documented. The loss of this 

efficiency, and the sub-optimal use of the transmission system that would follow, 

will reduce competition and increase costs overall to consumers in PJM. 

Finally, CFTC jurisdiction could require RTOs such as PJM to register as derivatives clearing organizations (‘‘DCOs’’). RTOs would then have to establish admission 

and financial eligibility standards for organizations who wish to do business within 

RTO markets. Users of PJM markets range from very large utilities to very small 

municipal systems, as well as industrial and commercial customers. FERC’s regulation has been designed to ensure nondiscriminatory access to these markets by all 

commercial entities, regardless of size. Any requirement that PJM impose these new 

financial eligibility standards—standards that are more applicable to traders on 

large exchanges—could prove difficult and costly for small entities such as small 

utilities, renewable resource developers and end-use customers. In essence, this 

would be placing a barrier to PJM’s competitive wholesale markets with little demonstrated concomitant benefit. 

Question 3. Your testimony states that PJM has never found a CFTC-registered 

clearinghouse interested in or able to clear the FTR positions of PJM’s market participants. Could you describe the reasons why registered clearinghouses declined to 

take the business of clearing FTR positions in PJM? 

Answer. In 2004, PJM’s management met repeatedly with clearinghouses and 

clearing organizations to examine the potential for credit clearing services to be provided to PJM’s members. PJM was advised in this matter by Deloitte & Touche. 

Based on these discussions, the following basic challenges became apparent: (1) calculating variation margin (or marking the position to market) would be difficult or 

impossible given the infrequently established reference prices that in turn result 

from FTR Auctions occurring only once every month, and insufficient secondary 

market trading of FTRs between auctions, (2) the risk of unforeseen grid outages 

and other physical factors that can dramatically affect the expected future value of 

an FTR position, making it very difficult for a clearinghouse to properly assess price 

risk; (3) the differing tariffs governing FTRs among various RTOs, which limit the 

opportunity for netting of FTR positions across several RTOs, as would be necessary 

to support a viable clearinghouse; and (4) PJM’s inability at that time to novate positions to the clearinghouse due to the absence of clear legal authority to effect such 

novation. Some of these challenges are surmountable. Others could be managed only 

by significantly redefining the product as it exists today, potentially so radically as 

to reduce or eliminate the value of the FTR as a hedging tool for firm transmission 

customers. 

Question 4. If the CFTC found that PJM was required to become a Designated 

Clearing Organization, what steps would PJM have to take? Do you have cost estimates for those steps? From whom would you recover those costs? 

Answer. If the CFTC were to determine that PJM is a DCO, PJM would be required to register with the CFTC and to demonstrate that it complies with the 

CFTC’s ‘‘Core Principles’’ applicable to DCOs. As explained below, most of the 

CFTC’s DCO Core Principles are not well-suited for RTO markets because RTOs do 

not provide ‘‘clearing services’’ within the meaning of the Commodity Exchange Act 

(‘‘CEA’’) and offer products that (a) are integrally related to physical energy and 

transmission services, and (b) are not ‘‘futures,’’ or other forms of derivatives. 

The DCO Core Principles include: 
60 

• Financial Resources.—DCOs must demonstrate adequate financial, operational, 

and managerial resources to discharge their regulatory responsibilities. RTOs 

do not maintain default insurance, guarantee funds, or other tiers of protection 

(e.g., an intermediary default structure analogous to the role of futures commission merchants with respect to DCOs) to mitigate the impact of a participant 

default. Instead, RTOs require market participants to provide financial security 

(except where unsecured credit is permitted). When a member’s financial security is exhausted, the RTO will allocate the default shortfall to its members 

through a ‘‘default allocation assessment’’ according to the terms of the RTO’s 

Operating Agreement. If RTOs were required to adopt some or all of the financial safeguards used by DCOs, it would force PJM’s members to accept substantially higher operating costs and capital requirements (e.g., margin). PJM’s 

Members then would likely pass these costs on to ratepayers. 

• Participant and Product Eligibility; System Safeguards.—DCOs must establish 

appropriate minimum standards for the DCO’s participants and products. In addition, DCOs must establish and maintain a program of oversight and risk analysis to ensure the ongoing integrity of the DCO as a whole (including emergency 

procedures for data backup and disaster recovery). 

All RTO market participants are members of the RTO. There are no tiers of 

members (e.g., clearing or non-clearing members) and no minimum financial 

membership criteria, although members must comply with PJM’s credit policies. 

This is consistent with FERC’s general policy of encouraging open access to the 

RTO markets. Requiring RTOs to limit their membership, would undermine 

long-standing FERC policy regarding open, non-discriminatory transmission 

and power markets. 

Similarly, if RTOs are required to clear their products and services (including) 

FTRs) in a manner comparable to a DCO clearing futures contracts, RTOs may 

be forced to substantially modify or even eliminate those products because the 

RTO may not be able to conform simultaneously with both FERC’s and the 

CFTC’s regulatory requirements. For example, DCOs typically mark positions 

to market and collect variation margin based from market participants on a 

daily basis. FTRs are priced infrequently through auctions that typically occur 

only once a month. Each auction includes both buyers and sellers, but unlike 

a futures exchange where buyers and sellers enter into equal and opposite 

standardized contracts, the FTRs and the FTR market are defined by the physical characteristics of the transmission system. Because each FTR is essentially 

a customized product, FTR buyers and sellers cannot be matched to standardized contracts, and there is no certainty that any particular FTR will be priced 

in any given auction. Notwithstanding the CFTC’s regulatory requirements for 

DCOs, PJM cannot calculate its exposure using a current market reference 

price with any regularity, and therefore as a practical matter, cannot use daily 

demands for incremental collateral to manage risk. 

At a minimum, certain DCO Core Principle concepts, including daily margining 

and calculation of value-at-risk, would need to be translated to work within the 

limits of the RTO market. Notably, the CFTC’s regulatory requirements for 

credit risk management policies would need to be adjusted to rely more on a 

retrospective examination of price behavior and statistical modeling, and less on 

a real-time analysis of actual market conditions. Although some aspects of the 

regulatory program for DCOs may be beneficial, they are mostly incompatible 

with and cannot reasonably be applied to RTO markets and products. 

• Settlement Procedures.—DCOs must be able to complete settlements on a timely basis, even under adverse conditions. In addition, DCOs must adequately 

record the flow of funds associated with each cleared transaction, and must 

comply with the terms and conditions of any netting or offset arrangements 

with other clearing organizations. RTOs already maintain robust settlement 

systems. If necessary, these systems likely could be adapted to comply with the 

DCO Core Principles. 

• Protection of Customer Funds.—DCOs must develop and enforce standards and 

procedures to protect member and participant funds. This concept is inapposite 

to RTOs because RTOs are not themselves market participants. Indeed, definitional requirements imposed on RTOs by FERC, requiring independence, prevent RTOs from proprietary trading in its own account while at the same time 

serving as a custodian for accounts of customers also participating in the RTOs 

markets. Again, this principle follows from the intermediary structure of seat 

holders and ‘‘futures clearing merchants’’ characterizing exchanges and clearinghouses respectively. This structure does not characterize RTOs. 
61 

• Rules and Procedures.—DCOs must publish all rules and operating procedures, 

including rules to ensure the efficient, fair, and safe management of events 

when members or participants become insolvent or otherwise default on their 

obligations. In addition, DCOs must demonstrate adequate ability to monitor 

and enforce compliance with the DCO’s rules (such as, through either internal 

resources or arrangements with an outside compliance organization). RTOs 

have the ability to allocate member defaults through a ‘‘default allocation assessment’’ that is similar to the procedure used by DCOs in the event of a member default. Other aspects of the DCO Core Principles do not reasonably apply 

to RTOs. For example, the ‘‘customer priority rule’’ cannot apply to RTOs because RTOs do not themselves engage in the markets they administer. Similarly, although DCOs are required to maintain extensive surveillance and enforcement programs, this role in RTO markets is performed by FERC and the 

RTO’s independent market monitor. RTOs are not self-regulatory organizations 

as that concept is applied by the CFTC; rather they are heavily regulated organizations subject to comprehensive oversight by the FERC. 

• Reporting and Recordkeeping.—DCOs must provide to the CFTC all information necessary for it to oversee the DCOs’ activities. In addition, DCOs must 

maintain all business records for five years in a form acceptable to the CFTC. 

RTOs already comply with extensive FERC reporting and recordkeeping requirements. Although RTOs likely could comply with this DCO Core Principle, 

the CFTC’s reporting and recordkeeping requirements may be duplicative of, 

and less comprehensive than, the requirements already imposed by FERC. 

The DCO registration process takes approximately six months from the date when 

a DCO application is submitted, unless the CFTC’s Division of Market Oversight 

grants an applicant’s request for an expedited 90-day review. The process of preparing the DCO application is, however, time-consuming and expensive. Therefore, 

the complete registration process will likely take considerably longer than six 

months. 

Question 5. Could you describe some of the attributes of FTRs that you believe 

distinguish them from futures? 

Answer. The CEA has never defined what constitutes a contract for future delivery. However, precedent from the CFTC and various federal courts has identified 

the following common characteristics of futures contracts: 

• Standardized, non-negotiable terms. 

• Future delivery. 

• Ability to enter into equal and opposite offsetting transactions. 

• Price at which the underlying commodity will be delivered in the future is fixed 

on the date when a market participant enters into a futures contract. 

• Offered to the public. 

• Secured with margin. 

These elements of a futures contract generally do not apply to FTRs. 

FTRs are not standardized and are not fungible. Each FTR is based on the hourly 

congestion price differences across a particular transmission path in the Day-Ahead 

Energy Market (i.e., the price difference between any two locational marginal price 

(‘‘LMP’’) points within an RTO system). FTRs can vary in terms of quantity (in MW) 

and duration (e.g., one month, three months, etc.). In each FTR Auction, there are 

hundreds of thousands of possible FTR combinations upon which market participants may bid. In contrast, NYMEX futures contracts for electricity are based on 

the price of electricity between two fixed time periods, and at a few highly liquid 

nodes. 

FTR positions cannot be financially settled or closed-out through offsetting transactions. A long (purchase) futures contract can be settled by purchasing an equal 

and opposite ‘‘offsetting’’ short (sale) futures contract. In contrast, FTRs must only 

be, as a whole, ‘‘simultaneously feasible’’ such that all outstanding positions remain 

within the physical limitations of the transmission system. In other words, for each 

long FTR position, there is not necessarily one single equal and opposite short position held by another market participant. A long FTR between two LMP points (A 

to B) may be closed out, in whole or in part, by a combination of FTR positions involving different but related LMP points (C to D and D to E, for example, where 

actual physical flows on paths C to D and D to E involve some flow of electrons 

across path A to B). This is fundamentally different from a futures contract and how 

futures markets operate. 

FTRs are not offered to the general public. FTRs are offered only to members of 

a particular RTO, which typically consists primarily of transmission owners, load 
62 

1Testimony of Vincent P. Duane, Vice President & General Counsel PJM Interconnection, 

L.L.C. Impacts of Potential Financial Markets Reform Legislation on Organized Wholesale Electricity Markets’’ March 9, 2010. 

serving entities, generation owners, electric distributors, end-use commercial and industrial customers, and power marketers. 

FTRs are not secured through daily margin payments. Each RTO establishes credit requirements according to a process set forth in its respective, FERC-approved 

tariff. For example, some RTOs establish credit requirements for market participants holding FTRs retrospectively by reference to the historical value of the positions, adjusted by a factor designed to reasonably anticipate atypical market conditions. Because FTRs are allocated through an auction based process, it is not possible to establish values for FTRs even on a monthly basis. In each FTR Auction, 

only a small fraction of the potential FTR combinations are bought or sold. As a 

result, there is insufficient liquidity across the numerous FTR paths to establish 

daily ‘‘market’’ values for forward FTR positions, and therefore, insufficient market 

information to support more frequent margin calculations. 

Question 6. In 2003, PJM revised its market rules so that FTRs were available 

to all transmission service customers and PJM members. What motivated that revision? 

Answer. On June 1, 2003, in response to a request by customers to provide them 

with more liquidity and flexibility, PJM supplemented the direct allocation of FTRs 

with an allocation of ‘‘auction revenue rights’’ or ‘‘ARRs’’ coupled with an Annual 

FTR Auction. This change gave firm transmission customers the option to receive 

the economic value of the FTR (as realized in an auction) or instead, simply convert 

the ARR to the underlying FTR, so as to replicate the direct FTR allocation outcome 

that existed prior to June 1, 2003. Auction revenue rights can be regarded as the 

financial proceeds realized by selling the underlying FTR in an auction. Since FTRs 

are specific to particular geographic points on the grid, customers may find that 

they are unable to receive an allocation of all the precise FTR paths they might request. In such cases, they may prefer to retain the auction revenue rights in place 

of the FTR, and use the proceeds realized by selling one FTR to purchase another 

that better suits their changing supply obligations or perception of expected patterns of congestion. 

In short, the institution of an auction marketplace for FTRs in 2003, as requested 

by wholesale customers, provided further options to those transmission customers 

entitled to an allocation of FTRs. First, establishing a marketplace provided these 

customers a forum to sell FTRs and buy alternate FTRs that might better match 

their hedging needs, given the location and nature of the load they served. Second, 

it provided efficiency through a transparent auction environment that ensured that 

a party placing the greatest value on a specific FTR was able to procure that FTR. 

Often, the party placing the greatest value on a particular FTR (thereby willing to 

pay the highest price for this FTR) is not the party to whom the FTR is originally 

allocated. In such a case, the original holder would prefer receipt of the auction revenue rights associated with that FTR (i.e., the price realized for that FTR in the 

auction) rather than the FTR itself. This change was endorsed by the PJM stakeholders and approved by the FERC. 

RESPONSES OF VINCENT P. DUANE TO QUESTIONS FROM SENATOR MURKOWSKI

Question 1. Is there currently a regulatory gap we’re trying to plug for electric 

market mechanisms like Financial Transmission Rights? Aren’t FTRs already regulated by FERC through its review and approval of RTO tariffs? 

Answer. No, there is no regulatory gap that needs to be filled as FTRs and the 

FTR Auction process are subject to pervasive regulation by FERC. As stated in my 

testimony (Section 4b), virtually from the inception of PJM’s markets, FERC directed the creation of FTRs as a means to allocate to transmission customers equitable access to the transmission grid. In PJM, the FTR product was approved by 

FERC more than a decade ago upon the creation of PJM’s organized markets in 

1997. 

Furthermore, in section 217 of the EPACT of 2005 Congress states its intention 

that FERC regulate FTRs comprehensively, including their formation, initial allocation, and transfer among various entities, as well as the trading of any excess FTR 

rights. PJM believes that Section 217 makes clear that the Congress intended for 

the FERC to regulate FTRs because of their inextricable link to the underlying 

transmission grid and electricity market structure. The plain language of Section 

217 indicates, in our opinion, Congress’ desire that the FERC’s regulation should 

be unambiguous in this area, guided by its expertise in transmission regulation.1
63 

Question 2. Why can’t utilities clear their derivative transactions on exchanges 

like other standardized commodities? 

Answer. To the extent this question refers to derivative transactions that take 

place in over the counter environments, PJM does not take a position on the merits 

of clearing standardized derivatives or an end user exemption to mandatory clearing. If the question refers to arguably derivative products in RTO environments, 

such as the FTR, PJM would respectfully reference its prior answers to Senator 

Bingaman’s questions 3-5 above. 

Question 3. What role do financial entities play in the organized wholesale electricity markets? I understand that in addition to bringing in needed liquidity some 

financial entities, like J.P. Morgan, have actual electric delivery obligations. 

Answer. Financial entities can play an important role in wholesale electricity markets. With the introduction of competitive retail service in several PJM states, entities such as Morgan Stanley, Goldman Sachs (J. Aron) and J.P. Morgan act as ‘‘load 

serving entities’’ in PJM. Moreover, many traditional utility or energy companies 

maintain proprietary trading businesses that, in part, financially optimize and 

hedge the physical generation and load positions of their affiliate utility operations, 

but also trade in PJM’s markets, in much the same manner as ‘‘financial entities.’’ 

For these reasons, PJM would suggest that rather than drawing distinction between 

‘‘financial entities’’ and other entities, it may be more helpful to distinguish between 

speculation and hedging, keeping in mind that both financial entities and traditional energy companies can engage in both functions from time to time. 

Trading (by ‘‘financial entities’’ or energy company/utility affiliates) is valuable to 

PJM’s markets and promotes efficiency and lower prices, up to a point. Excessive 

speculation, concentration of risk, and abusive trading can distort pricing and result 

in costs to consumers. PJM and FERC guard against these risks through active 

market monitoring and enforcement by both an independent market monitor and 

FERC itself. Furthermore, PJM continuously refines its market rules to manage 

these risks, and is currently in dialogue with its stakeholders and FERC about such 

concepts as the role of unsecured credit, position limits, minimum net worth requirements for participants and limits on aggregate financial guarantees. 

Question 4. Aren’t FTRs directly tied to the physical limitations of the grid meaning there’s a finite amount in the market? Please explain. 

Answer. Yes. FTRs are financially-settled products that transmission customers 

use to hedge against the cost of congestion, that are directly tied to the physical 

characteristics and limitations of the transmission system. FTRs can be created only 

by RTOs or ISOs and their number and composition is determined based upon the 

transmission system topology and the physics of physical power flows. 

Congestion occurs when the least costly resources available to serve load in a 

given area cannot be dispatched because the physical limitations of the transmission 

lines located between the source point (sending end/generator) and the sink point 

(receiving end/customer site) prevent the movement of electricity from these generation resources to the load. FTRs help hedge congestion risk by providing payments 

that are proportional to the congestion that transmission customers would encounter over a specified transmission path. 

In order to provide an effective risk management product, the FTRs that are 

awarded through the auction process must correspond to the actual transmission capabilities of the system. If too many FTRs are awarded for a certain transmission 

path, the RTO would be over-committed and the efficacy of the FTR as a hedging 

tool would be compromised. To maintain the integrity of the FTR market, the FTR 

Auction process relies on a linear algorithm that only awards FTRs to bidders who 

have submitted a ‘‘simultaneously feasible’’ combination of bids. A combination of 

bids is ‘‘simultaneously feasible’’ if the RTO’s actual transmission system can accommodate simultaneously transmitting the electricity underlying each FTR transaction. Because of the physics associated with transmitting electricity, the total 

quantity of FTRs can increase above the nominal capacity of the transmission system if there are prevailing flow and counterflow FTRs over the same transmission 

path. However, even in this case, the total number of FTRs in the market is absolutely limited by the physical characteristics of the transmission system. 

Question 5. In 1998, PJM, the largest wholesale electric market in the world, 

asked the CFTC through a No Action letter to clarify certain regulatory uncertainties related to the RTO’s standing as a Derivatives Clearing Organization. It is my 

understanding that the CFTC failed to respond for over a decade but just recently 

turned to this issue, is that correct? What was the agency’s reason for failing to consider the request in a timely manner? How is this regulatory certainty impacting 

the organized markets? 

Answer. On October 19, 2000, PJM filed a request with the CFTC’s then Division 

of Trading and Markets for no-action relief. As required by CFTC rules, PJM peri-
64 

odically provided the Division with updated or supplemental information. PJM believes that it has a very professional and constructive relationship with the CFTC 

and its Staff. We are not, however, privy to the CFTC’s internal activities or deliberations relative to PJM’s no-action request, and accordingly, cannot offer the Committee any insight on this subject. 

PJM is concerned that if the present uncertainty continues, decreased liquidity 

and increased volatility will ultimately raise costs for consumers and compromise 

the integrity of PJM’s markets. The most troubling aspect of the recent public attention given by the CFTC to the FTR markets is the potential for a defaulting FTR 

holder to allege that the FTR is illegal and unenforceable because it was not traded 

in an environment registered with or overseen by the CFTC. Hopefully, this risk is 

remote. Resolution of the pending no-action request in a manner which does not 

raise the specter that these products needed to have been registered with the CFTC 

since their inception would remove this risk. 

Question 6. Didn’t PJM at one point approach NYMEX regarding these RTO-market instruments and the Exchange had zero interest in clearing those products? 

Wasn’t the rationale because the risk associated with instruments like FTRs are 

tied to the realities of the system? 

Answer. PJM has explored clearing services from a CFTC-registered clearinghouse, but has never found a DCO willing or able to clear PJM’s FTR product. As 

discussed above in response to Senator Bingaman’s question 3, the physical characteristics of PJM’s FTR product and the special requirements of PJM’s FERC-regulated markets make the clearing, as defined by the CFTC, of FTRs impossible. Instead, PJM has implemented credit policies and mechanisms to protect the integrity 

of its markets that are tailored to its products and the services it offers. These provisions, developed in consultation with FERC and codified in its tariff, are as effective as the CFTC’s Core Principles, but also compatible with how RTO markets are 

required to function. 

RESPONSES OF JOSEPH T. KELLIHER TO QUESTIONS FROM SENATOR BINGAMAN

Question 1. What would CFTC jurisdiction over FTRs mean for FPL Group, its 

customers and, more generally, ratepayers located in RTO/ISOs? 

Answer. FPL Group has two principal subsidiaries: NextEra Energy Resources, 

LLC, the owner of competitive generation assets and an energy marketing company 

(NextEra Energy), and Florida Power & Light Company (FPL), a vertically integrated utility in Florida. NextEra Energy operates in 26 states and is the largest 

wind developer in the United States. 

The Commodity Futures Trading Commission (CFTC) jurisdiction over FTRs may 

have a variety of impacts on NextEra Energy and its customers. First, NextEra Energy would be eligible for certain regulatory exclusions and exemptions because it 

is an ‘‘eligible contract participant’’ (ECP), as currently defined by Commodity Exchange Act (CEA). As an ECP, transactions involving FTRs would be exempt from 

all but the anti-manipulation provisions of the CEA to the extent that FTRs are considered to be transactions in ‘‘exempt’’ commodities. Therefore, under current law, 

NextEra Energy’s transactions in FTRs are subject to overlapping anti-manipulation 

authorities by FERC and CFTC. 

Should the CFTC assert jurisdiction over FTRs, NextEra Energy’s transactions in 

FTRs could be subject to clearing and margining requirements, which would increase NextEra Energy’s transaction costs. These increased costs likely would be 

passed along to our ratepayers. In addition, the CFTC could apply position limits 

to transactions in FTRs, which could undermine or limit the ability of utilities and 

other RTO participants to utilize this important tool in managing transmission congestion costs. 

CFTC regulation of FTRs is likely to be different than FERC regulation in other 

respects. While FERC has allowed most FTRs to be allocated to load-serving utilities on a long-term basis to assure just and reasonable rates, I would expect the 

CFTC may require auctioning of all FTRs, which would make it much more expensive for load-serving utilities to manage congestion risk. Moreover, CFTC may also 

disfavor long-term transmission rights, and shorten the term of FTRs. That would 

be directly contrary to legislative provisions in the Energy Policy Act of 2005 that 

govern FERC, but not the CFTC, so those provisions do not bind the CFTC. This 

approach would expose consumers to transmission congestion risk, greater price volatility, and less predictable prices. 

Under the proposed amendments to the CEA contained in H.R. 4173, it appears 

that FTRs may fall within the definition of a swap. If that is correct, under the 

amended CEA, FTRs would be subject to the exclusive jurisdiction of the CFTC, not-
65 

withstanding FERC’s traditional role as the principal regulator of RTO and ISO 

markets. This jurisdictional change would create uncertainty about the FERC’s continuing oversight role, if any, over FTRs and other aspects of RTO markets. As 

swaps, FTRs may be subject to mandatory clearing (depending upon whether they 

are considered hedges and whether parties who enter into hedges are considered 

Major Swap Participants under the legislation), which, as noted above, may subject 

them to margining requirements and increase NextEra Energy’s transaction costs. 

Regulatory uncertainty typically increases transaction costs, which likely would 

have to be passed along to ratepayers. 

Question 2. Are EEI members that operate within RTO and ISO markets recipients of allocated FTRs? How would these members and their ratepayers be affected 

by CFTC jurisdiction over FTRs? What would it mean for these companies and their 

ratepayers if FTR allocations were revised or altered? 

Answer. EEI’s members are U.S. shareholder-owned electric companies that serve 

95 percent of the ultimate customers in this segment of the industry and represent 

approximately 70 percent of the U.S. electric power industry. Many EEI members 

operate within RTO and ISO markets that offer FTRs or comparable products. 

The manner in which transmission customers acquire FTRs is governed by the 

terms of the applicable RTO or ISO tariff, which is subject to FERC regulation. In 

many markets, FTRs are awarded through an auction process. In each auction, bids 

submitted by prospective FTR holders are evaluated using a software algorithm that 

determines the most economic combination of bids that still falls within the limits 

of the system’s actual capacity (i.e., the best combination that is ‘‘simultaneously 

feasible’’). Notably, some otherwise economic bids may not clear the FTR auction 

due to the physical limitations of the transmission system. 

RTO and ISO markets that allocate FTRs through an auction also may provide 

firm transmission customers with a form of ‘‘auction revenue rights’’ to offset the 

cost they incur acquiring FTRs that correspond with their transmission positions. 

Auction revenue rights are not FTRs, but in the markets where they exist, they can 

typically be converted into FTRs through the FTR auction process. 

Some RTO and ISO markets also allocate FTRs through direct sales to transmission owners, direct allocations for contributions made to network upgrades, or 

conversions of transmission capacity associated with certain existing transmission 

agreements. 

CFTC jurisdiction over FTRs and the FTR auction process would complicate RTO 

and ISO efforts to comply with FERC Order No. 2000 by making it more difficult 

for transmission customers to manage their congestion risk. Transmission customers 

who rely on FTRs would immediately face substantial uncertainty as to whether 

FTRs qualify as regulated futures contracts (under existing law or the proposed 

CEA amendments) or swaps (under the proposed CEA amendments), or whether 

they may be exempt from regulation under one or more statutory or regulatory provisions. In addition, the FTR auction process would create uncertainty as to whether 

RTOs and ISOs may need to register as a contract market or comply with the requirements applicable to CFTC-regulated ‘‘trading facilities.’’ More generally, the 

CFTC may assert that the RTO or ISO provides clearing services that requires it 

to register as a derivatives clearing organization. The uncertainty resulting from 

any one of these scenarios would undermine the viability of the FTR process. 

If RTO and ISO market participants are unable to use FTRs to hedge their congestion risk, many of EEI’s members and their rate-paying customers will be exposed to greater electricity price volatility and less predictable prices. 

Question 3. Are EPSA members that operate within RTO and ISO markets recipients of allocated FTRs? How would these members and their customers be affected 

by CFTC jurisdiction over FTRs? What would it mean for these companies and their 

customers if FTR allocations were revised or altered? 

Answer. EPSA is the national trade association for competitive wholesale power 

suppliers, including generators and marketers. EPSA members include both independent power producers and the competitive wholesale generation arms of certain 

utility holding companies. The competitive sector operates a diverse portfolio that 

represents 40 percent of the installed generating capacity in the United States. 

EPSA members do business nationwide, both in the two-thirds of the country served 

by RTOs or ISOs and the remaining one-third of the country dominated by traditional vertically-integrated utilities 

Although merchant generators are not allocated FTRs by the RTOs, these FTRs 

underpin the pricing, reliability and congestion management of the entire RTO. 

Therefore, all of the consequences enumerated in the response to question #2 would 

apply to EPSA members, who rely on well-functioning RTO markets to provide 

wholesale electric service to their customers. 
66 

1 Calculation made as of September 30, 2009. 

2 Calculation made as of March 24, 2010. 

Question 4. FPL Group’s subsidiary NextEra Energy is a competitive generator 

and the largest wind developer in the United States. Does CFTC jurisdiction over 

FTRs or other products create a disincentive to invest in renewable generation, 

transmission infrastructure, or new technology? 

Answer. Regulatory uncertainty is never an incentive to investment in any endeavor, including renewable generation and transmission infrastructure. To the extent that Congress determined that FTRs and other ISO products were to be solely 

regulated by the CFTC and not the FERC then the answer to your question would 

largely depend on the nature of the regulations and consistency of oversight in conjunction with the other interrelated FERC jurisdictional products associated with 

building, interconnecting and running renewable generation or transmission infrastructure. 

CFTC regulation of FTRs would introduce significant risk into their renewable energy development decisions, since they would bear the risk associated with this uncertainty. Some wind developers build merchant projects that are not backed by 

long-term contracts. The uncertainty regarding FTRs would introduce significant 

risk in their investment decisions, since they would bear the risk of transmission 

congestion. Wind developers that build under contract are typically not the party 

most concerned with congestion and transmission regulatory issues because such 

risks are frequently passed on to the off-taker of the power under the terms of the 

Power Purchase Agreement (PPA). However, to the extent CFTC jurisdiction over 

FTRs and other ISO products creates additional regulatory risks or uncertainty, or 

creates or increases the risk of regulatory conflicts for products that were once 

under a single regulatory construct for the off-taker, the off-taker is likely to account for such risk by reducing the contract price paid under the PPA. That would 

make some projects uneconomic. 

Any reduction in prices received for the power would negatively impact the ability 

of the developer, who will rely on the PPA price to inform its investment decision, 

to obtain financing for the project. In many if not most instances, a renewable investment that cannot be financed will not be built. 

Therefore, the primary issue is not so much one of an upfront cost impact on 

NextEra Energy development, but one of regulatory uncertainty and its likely implications on the economics of renewable investment. Entry by the CFTC into traditionally FERC-regulated products will disrupt and bifurcate the current unitary regulatory scheme, with such regulatory uncertainty leading to a disruption of the marketplace, resulting in increased costs in the areas of both compliance and risk mitigation for all parties involved in the product chain and lower prices for renewable 

project developers. 

Question 5. Your testimony states that the requirement to clear and/or trade 

transactions on an exchange would materially increase both wholesale and retail 

rates. Has FPL Group sought to estimate the scope of these rate increases? 

Answer. As a competitive power company, renewable energy provider, and 

vertically integrated utility, FPL Group has been closely following the financial reform legislation from the perspective of its impact on our customers, who are wholesale and retail electric consumers. FPL Group has calculated the amount of additional margin that it would be required to post if all OTC transactions were required to be traded on exchange several times in the last year. FPL Group has made 

these calculations to ascertain at a high level how much of an impact the legislation 

would have on energy costs. NextEra Energy would be required to post approximately $100,000,0001 in incremental margin and FPL, our utility, would be required to post approximately $600,000,0002 in incremental margin. The costs of transacting 

on exchange or through a clearinghouse due to delivering large amounts of incremental margin to the exchanges or clearinghouses would likely end up as additional 

costs ultimately to be absorbed by end-users and ratepayers. 

Rather than trying to pin down all the variables needed to estimate a dollar per 

megawatt impact to wholesale and retail rates, the real focus should be on the 

broader issue of energy companies and end-users having to raise enormous amounts 

of capital without a corresponding increase in revenues at a time when that capital 

is needed to start rebuilding the economy. Nevertheless, we believe such costs could 

end up materially increasing wholesale and retail rates given the sheer size of the 

incremental margin that will be needed. 

The purpose of the broader financial regulatory reform legislation is to reduce systemic risk in the financial sector. In my view, a requirement to clear and trade energy commodities does not reduce systemic risk in any fashion, and instead introduces liquidity risk associated with posting margin. While FPL Group supports the 
67 

goal of financial regulatory reform, the ability of electric and natural gas companies 

to use OTC energy derivatives for legitimate business purposes should be preserved. 

RESPONSES OF JOSEPH T. KELLIHER TO QUESTIONS FROM SENATOR MURKOWSKI

Question 1. Is there currently a regulatory gap we’re trying to plug for electric 

market mechanisms like Financial Transmission Rights? Aren’t FTRs already regulated by FERC through its review and approval of RTO tariffs? 

Answer. There is no regulatory gap in the regulation of FTRs. FTRs are fully regulated by FERC under FERC-approved tariffs, and have been since the RTOs began 

using these products more than a decade ago. There has been no assertion of a gap 

in regulation. Instead, a question has been raised of whether or not FTRs have attributes of commodities or derivatives, and, therefore, are subject to overlapping regulation by CFTC under the CEA. We believe that allowing such regulatory overlap 

would undermine the effectiveness of FTRs in addressing congestion within the 

RTOs and raise costs to RTO participants and the consumers they serve. 

Question 2. Why can’t utilities clear their derivative transactions on exchanges 

like other standardized commodities? 

Answer. EEI and EPSA members use OTC derivatives extensively to manage 

commodity price risk for electric power, natural gas and other fuels, as well as to 

contain risk-related costs when financing energy infrastructure. A requirement to 

clear all derivatives transactions would greatly reduce the ability of companies to 

find the customized derivative products they need to manage their risks because 

clearinghouses and exchanges require a high level of margin and collateral for the 

derivatives and commodities products traded. 

Customization of contracts is necessary for everything from specific delivery 

points in electricity to quantities of natural gas. Without the ability to use these 

customized transactions, energy suppliers would be severely constrained in the 

types of products and the costs of those products that could be offered to consumers. 

In addition, for centrally cleared products to be effective, standardization and a critical mass of market participants are essential. For example, in the case of electricity, since its unique physical nature precludes significant storage and requires 

that it be consumed when generated in hundreds of physical markets, the prerequisites for standardized and centralized clearing are missing. So, electricity price 

risk cannot be managed through a selection of exchange-traded contracts. Rather, 

such derivatives often require customization in order to be effective. 

While centrally cleared exchanges strictly require cash collateral, individually negotiated OTC contracts allow hedging entities to use alternative collateral structures such as asset liens, credit lines or no collateral below agreed upon thresholds. 

Providing such flexibility frees up scarce capital for investments in energy infrastructure. Conversely, not allowing such collateral structures and forcing all OTC 

transactions to clear through exchanges would unnecessarily divert substantial capital from productive investments and drive up the price of energy commodities. 

Limiting access to these risk management tools by mandating the clearing of OTC 

transactions would jeopardize the ability of energy providers to manage risks, increase consumers costs and increase excessive consumer exposure to market volatility. The OTC derivatives markets’ very purpose is to provide customized solutions 

that meet the individual needs of customers with flexible products as well as diversified margin and collateral requirements. Provisions requiring clearing of transactions will only increase costs and limit market participants’ ability to manage 

risks without creating comparable offsetting benefits. 

Question 3. Mr. Kelliher, as a former FERC Chair, you’ve stated that an MOU, 

as called for in the House-passed legislation, is insufficient to resolve jurisdictional 

issues between FERC and CFTC. Please explain. 

Answer. As FERC Chairman, I entered into a number of Memoranda of Understanding (MOU) with other federal and state agencies, including the CFTC. An 

MOU is a useful vehicle for two or more agencies to coordinate how they will exercise their respective legal authority in a manner that avoids or minimizes conflict 

between the agencies, improves their ability to discharge their respective statutory 

duties, and provides greater transparency to the regulated community. 

However, the MOU in the House bill has an altogether different purpose. The purpose of the MOU provision in section 3009 is not to coordinate how FERC and the 

CFTC will exercise their jurisdiction, but to define the jurisdiction of the two agencies. With respect, I believe that is the duty of the Congress and is not something 

that should be the subject of a MOU. 

Under section 3009(a)(1) the CFTC and FERC are directed to negotiate an MOU 

to ‘‘establish procedures for applying their respective authorities in a manner so as 

to ensure effective and efficient regulation in the public interest, resolving conflicts 
68 

3 Calculation made as of March 24, 2010. 

4See For Utilities, Derivatives is not a Dirty Word, Energy Daily, October 7, 2009. 

concerning overlapping jurisdiction between the two agencies, and avoiding, to the 

greatest extent possible, conflicting or duplicative regulation.’’ 

As was discussed at the hearing, there is a jurisdictional disagreement between 

FERC and the CFTC. The heart of the dispute is that FERC has interpreted the 

anti-manipulation authority granted by Congress in the Energy Policy Act of 2005 

as requiring it to police market manipulation in futures market that affects jurisdictional wholesale power and natural gas markets. The CFTC objects to this interpretation, and would prefer that FERC limit the scope of its anti-manipulation authority. 

This disagreement has now endured for nearly three years, and has spilled into 

litigation regarding FERC enforcement proceedings against companies it believes 

engaged in market manipulation. There is no reason to expect that either agency 

will alter its position, since both agencies appear to interpret current law regarding 

their respective jurisdiction and statutory duties differently. As a practical matter, 

if the two agencies disagree on how to interpret current law, there is no reason to 

expect an MOU can resolve that disagreement. 

In my opinion, the MOU provision of H.R. 4173 will prove ineffective because the 

agencies are unlikely to agree on jurisdictional boundaries, and an MOU that defines the respective jurisdiction of the two agencies is unlikely to be entered into. 

The disagreement will continue. 

Congress can compel two agencies to begin a discussion about a possible MOU, 

but Congress cannot compel the agencies to agree on how to interpret current law 

through the device of an MOU negotiation. If Congress wants to ‘‘resolv[e] conflicts 

concerning overlapping jurisdiction between the two agencies’’ it should pass substantive legislation to define their respective jurisdictions. 

At this point, it appears that only Congress or the courts can define the respective 

jurisdiction of FERC and the CFTC, the Congress through legislation that clarifies 

jurisdiction, the courts through orders interpreting current law. A MOU is no sort 

of solution to the jurisdictional disagreement between the two agencies. 

Question 4. You’ve testified that forcing trading on exchanges would cost hundreds 

of millions of dollars for the average utility or generation company and that the 

margin and collateral requirements would tie up large amounts of cash, creating 

‘‘dead’’ capital. What would the cost impact of CFTC regulation of FTRs and OTC 

transactions be for a utility like Florida Power and Light? 

Answer. If the current legislative proposals were to pass and all standardized 

OTC transactions were required to be traded on exchange or cleared, then FPL 

would be required to post approximately $600,000,0003 in incremental margin. 

While FPL is considered a very large utility, this number is consistent with other 

estimates of the impact the OTC legislation could have on investor-owned utilities. 

EEI President Tom Kuhn has stated that the increased costs of requiring OTC 

transactions to be transacted on exchanges would be ‘‘astronomical—in the neighborhood of hundreds of millions of dollars annually for an average utility.’’4 There 

are currently approximately 200 investor-owned utilities in the United States. The 

total cost to the electric utility sector alone would be many billions of dollars. 

This amount does not include any amounts of incremental collateral that would 

be required to be posted by other energy participants such as: (i) non-investor-owned 

utilities, (ii) other end-users (wholesale generators and other non-utility energy consumers), (iii) wholesale commercial energy companies, (iv) dealers, (v) speculators, 

and (vi) other energy commodity participants in the natural gas market. The overall 

impact of the OTC legislation would be to cause thousands of companies to either 

(i) raise billions of dollars in additional capital for incremental margin, above and 

beyond what is required in the current regulatory construct, or (ii) drop their hedging activities in part or in total and take on market risk rather than trying to raise 

capital. 

In this slowly recovering economy, it is difficult to imagine the impact on the financial markets as companies try and raise billions of dollars within a short 

regulatorily mandated time period. To make matters worse, those entities will have 

to raise those amounts without being able to project a corresponding increase in revenues in order to pay back the capital or deliver a return. Additionally, those billions of dollars that would then be used for margining will displace capital that 

would have otherwise been used for capital investment projects at a time when capital investment is most needed. 

With respect to possible CFTC regulation of FTRs and other RTO/ISO products, 

that is more of a concern for NextEra Energy than it is for FPL because FPL is 

not located in an RTO/ISO. The impact on NextEra Energy, which transacts in the 
69 

RTO/ISOs that sell FTRs, relates more to regulatory uncertainty than direct costs. 

Entry by the CFTC into traditionally FERC regulated products will disrupt and bifurcate the current unitary regulatory scheme, with such regulatory uncertainty resulting in increased compliance and risk mitigation costs for all parties involved, 

and lower prices for renewable energy developers. 

Question 5. Don’t regulated utilities use instruments like FTRs to keep consumer 

prices stable? You don’t really make any money from hedging, do you? 

Answer. Regulated utilities use FTRs to help manage risk. They buy FTRs to 

manage, or hedge, the amount they will have to pay for congestion. Without the 

ability to manage this risk, costs would go up and consumers would be subject to 

the volatility that results from the occurrence of transmission congestion. 

The purpose of hedging is not to make money, but instead to lock in prices or remove volatility from various commodity inputs used to generate or deliver electricity 

over a certain period of time. 

The way a hedge works is when the value of the underlying commodity is up, then 

the value of the hedge contract is down. And vice versa, when the value of the underlying commodity is down, then the value of the hedge contract is up. The net 

result of this is a stable price for the hedging utility, which ultimately benefits retail 

electricity consumers. 

Question 6. Why do you believe it’s necessary for Congress to specify an end-user 

exemption for both wholesale and retail market participants? 

Answer. EEI and EPSA members engage in risk management transactions in the 

OTC derivatives markets to help ensure stable and affordable rates for customers 

in both the wholesale and retail electricity markets. As previously noted, the high 

cash margin requirements of clearing would significantly increase transaction costs 

for our members and, ultimately, their wholesale retail customers. In addition, it 

would tie up needed cash at a time when the cost of capital is high, access to capital 

markets is uncertain, and our industry needs to invest billions in renewable energy 

sources and clean energy infrastructure. As a result, our more capital-constrained 

members may choose to hedge fewer of their transactions, thereby increasing their 

risks and passing potentially volatile pricing onto wholesale and retail customers. 

RESPONSE OF JOSEPH T. KELLIHER TO QUESTION FROM SENATOR STABENOW

Question 1. Please share your views on whether the mandatory reporting of energy commodity contracts to regulated swap or derivative repositories is a regulatory solution that would meet the public policy goals of increasing market transparency, mitigating systemic risk, and providing price transparency, without hindering the ability for end-users to hedge their commercial risk or increasing costs 

to consumers. 

Answer. EEI and EPSA believe that promoting greater regulatory oversight and 

transparency of OTC derivatives markets through increased financial reporting and 

authority to the CFTC to prevent manipulation is a laudable goal of proposed financial reform. This transparency can be achieved in a cost-effective way through mechanisms such as mandatory reporting requirements and a central data repository, as 

opposed to mandatory clearing for energy. Reporting all OTC transactions to a central data repository would provide the CFTC a window for the first time into the 

OTC markets, without hindering the ability of end-users to efficiently manage their 

commercial risk. In addition, we support the clearing of standardized derivatives between large financial dealers, where appropriate, through regulated central counterparties to reduce systemic risk and bring additional transparency through information regarding pricing, volume and risk. Energy suppliers welcome the increased 

regulatory oversight and reporting through such a central data repository mechanism. 

RESPONSES OF JON WELLINGHOFF TO QUESTIONS FROM SENATOR BINGAMAN

Question 1. How would CFTC jurisdiction over FTRs affect FERC’ s overall mission of ensuring just and reasonable rates? 

Answer. CFTC jurisdiction over FTRs could significantly impair FERC’s ability to 

ensure just and reasonable rates. FTRs are an important tool for protecting customers against the risk of price increases for transmission services in RTOs/ISOs. 

Congress recognized the importance of FTRs when it enacted FPA section 217 as 

part of the Energy Policy Act of 2005, requiring FERC to use its authority in a way 

that enables load-serving entities to secure FTRs on a long-term basis for long-term 

power supply arrangements made to meet their customer needs. CFTC jurisdiction 

over FTRs could lead to, e.g., limits on the availability of FTRs for load-serving enti-
70 

ties and thus less protection for their customers against increases in transmission 

costs. 

Question 2. Chairman Wellinghoff’s testimony states that regulatory uncertainty 

could slow investments in renewable resources or smart grid technology. Would 

CFTC regulation of a financial instrument like FTRs have such far-reaching impacts? Please explain. 

Answer. Yes, CFTC regulation of FTRs could reduce investment in such resources. 

For example, as indicated in my answer to your Question #1, CFTC jurisdiction over 

FTRs could lead to limits on the availability of FTRs for load-serving entities. A 

load-serving entity considering whether to buy long-term power from a proposed 

wind farm would need to consider the expected cost of transmission, particularly if 

the wind farm would be far from the load. FTRs can help ensure that the expected 

transmission costs are unlikely to increase significantly. Without the certainty provided by FTRs, the load-serving entity might decide to continue buying short-term 

power and the wind farm thus might lack the customer commitment it needs to get 

financing and begin construction. 

Question 3. In his testimony, Vincent Duane from PJM Interconnection stated 

that the FTR is inextricably linked to locational priced energy markets. How could 

FERC and the CFTC fulfill their respective missions if they individually regulate, 

according to different standards, two ‘‘inextricably linked’’ products? 

Answer. Duplicative regulation of RTO/ISO markets would not be workable or 

wise. As I testified, all elements of RTO/ISO markets are approved by FERC, incorporated into FERC-approved tariffs and monitored closely by independent market 

monitors and FERC. CFTC regulation of one or more of these elements, such as 

FTRs, could disrupt the integrated functioning of these markets, leading to inefficiencies and higher energy costs for consumers. 

Question 4. How would CFTC jurisdiction over FTRs impair FERC’ s ability to 

protect against manipulation in the RTO markets? 

Answer. Under the Commodity Exchange Act, the CFTC asserts exclusive jurisdiction in the markets they regulate. Were the CFTC to acquire exclusive jurisdiction over the FTRs currently traded in RTO/ISO markets subject to FERC regulation, FERC’s authority to prevent and punish market manipulation in the RTO markets could be restricted. 

Question 5. Do you believe that an FTR defined by a particular source-sink combination is distinct from an FTR with a different source-sink combination? 

Answer. Yes. An FTR is a right based on congestion between two specific points. 

An FTR for congestion between Pittsburgh and Philadelphia is not fungible with an 

FTR between Pittsburgh and Hagerstown, MD. A loadserving entity seeking to buy 

power in Pittsburgh for delivery to customers in Philadelphia can benefit from an 

FTR between those two points, but not from an FTR for delivery in Hagerstown. 

PJM alone has thousands of such point-to-point combinations of FTRs, making them 

much less fungible than typical futures regulated by the CFTC. 

Question 6. Much of the discussion at the hearing focused on FTRs, which are 

available within RTOs and ISO markets. Do you have concerns with respect to possible CFTC jurisdiction over products that are available outside of RTO and ISO 

markets? 

Answer. Yes. For example, the definition of ‘‘swaps’’ in H.R. 4173 could be construed to include bilateral capacity contracts. Under this type of contract, a loadserving entity can assure its ability to meet its customers’ needs by buying the right 

to use certain resources?, a power plant’s output or a right to demand response) but 

does not have to commit to buy a specific amount of energy at an agreed-upon price. 

In an RTO/ISO market, capacity obligations help ensure that there will be enough 

‘‘steel in the ground’’ and other resources to meet the aggregate needs of the market’s customers. In bilateral markets, capacity contracts can serve the same purpose 

for an individual utility. In both organized markets and bilateral markets, capacity 

contracts can be critical in ensuring that a proposed resource has a projected revenue stream sufficient to allow development of the resource. 

RESPONSES OF JON WELLINGHOFF TO QUESTIONS FROM SENATOR MURKOWSKI

Question 1. Is there currently a regulatory gap we’re trying to plug for electricity 

market mechanisms like Financial Transmission Rights? Aren’t FTRs already regulated by FERC through its review and approval of RTO tariffs? 

Answer. There is no regulatory gap. RTOs/ISOs are comprehensively regulated by 

FERC. CFTC regulation of FTRs would not close a regulatory gap but would instead 

impose duplicative and potentially conflicting regulation. 

Question 2. According to former FERC Chairman Joe Kelliher, who is testifying 

today on the second panel, energy providers do not pose a systemic risk to the 
71 

broader economy. Instead, the entire commodities market is less than I percent of 

the global OTC derivatives markets, and the energy commodity portion is yet a fraction of that one percent. 

Do you agree that these electricity market instruments do not pose the kind of 

systemic risk Congress is trying to address in financial reform regulation? Ifso, isn’t 

this a good case for striking a reasonable balance? 

Answer. Amidst the recent meltdown of financial markets, electricity market instruments regulated by FERC did not at any time pose a systemic risk to the national economy. In addition to the relatively small size of the markets for the instruments, FERC already comprehensively regulates all RTO/ISO rates, terms, and conditions of service, including reviewing, approving, and revising credit practices. 

Question 3. There’s a concern that under the new financial reform legislation the 

RTOs and ISOs themselves could become subject to the CFTC’s jurisdiction as ‘‘derivative clearing organizations.’’ Is that appropriate? If RTOs were subject to the 

CFTC’s exclusive jurisdiction, what additional rules and regulations would be required? 

Answer. Regulation of RTOs/ISOs as ‘‘derivative clearing organizations (DCOs)’’ 

would be inappropriate because RTOs/ISOs are already regulated comprehensively 

by FERC. CFTC regulation of RTOs/ISOs as DCOs could subject them to conflicting 

requirements or could impair FERC’s ability to protect consumers from excessive 

rates. 

A DCO must demonstrate ongoing compliance with various ‘‘core principles’’ set 

forth in the Commodity Exchange Act and the CFTC’s regulations. These core principles are used to evaluate the DCO’s capabilities in such areas as adequacy of financial resources, risk management and settlement processes, and default procedures. The differences between DCOs and RTOs/ISOs make it difficult to determine 

the specific requirements the CFTC might impose on RTOs/ISOs. 

Whether the CFTC would, or even could, adopt rules and regulations to ‘‘harmonize’’ CFTC and FERC regulation of RTO/ISOs in order to recognize their unique 

characteristics and avoid inconsistent regulation is unclear. 

Question 4. If RTO products—or the RTOs themselves—became subject to the 

CFTC’s exclusive jurisdiction, wouldn’t that mean that FERC was precluded from 

fulfilling its mandate that consumer electricity prices be just and reasonable? 

Answer. The CFTC asserts that its jurisdiction under the Commodity Exchange 

Act is exclusive. If so, then CFTC regulation of RTO/ISO products or of the RTO/ 

ISOs themselves could limit FERC regulation and prevent FERC from fulfilling its 

statutory obligation to ensure just and reasonable rates. 

Question 5. As we talk about the problems associated with subjecting these transactions to a cash collateral clearing requirement, it’s easy to forget that transactions 

like FTRs are already subject to credit requirements. 

a. Can you please elaborate on how these credit requirements now work? 

Answer. FTRs provide revenue to the holder of those rights that can be used to 

insure against the costs associated with physical congestion on the electric grid. As 

you note, FTRs are subject to credit requirements. Generally speaking, the credit 

requirements are established based on an estimate of the cash flow associated with 

each FTR owned. Practically speaking, this means estimating the revenue for each 

year on a particular path, for example, between a location in central Pennsylvania 

and a location in southern New Jersey, to assess the risk that the FTRs, due to 

changes on the electric system, may not yield a positive cash flow. In these instances, the party owning the FTR will have to ‘‘pay’’ rather than receive payment. 

The risk being assessed is for non-payment. Based on this analysis, credit is extended based on factors relating to the risk profile of the particular market participant. The market participant currently can post collateral to meet this credit requirement using a combination of secured credit (e.g., cash or letters of credit) and 

unsecured credit (e.g., parent company guarantee). The RTO/ISO markets generally 

allow a certain amount of unsecured credit for more creditworthy entities although 

some have moved to prohibit unsecured credit in the FTR market and the Commission’s recent proposed rules on credit would remove unsecured credit in all FTR 

markets. 

b. Isn’t FERC currently considering whether to increase these credit requirements? Aren’t you also examining whether to require additional information regarding the reselling of FTRs in secondary markets? 

Answer. FERC has been actively looking at improving credit management in the 

RTO/ISO markets since their inception and has made several modifications. FERC 

addressed the issue generically in 2004 with a Policy Statement that spurred reforms on a case-by-case basis. In light of the financial crisis, the Commission in Jan-
72 

uary 2009 held a technical conference to examine the effects of the crisis on wholesale electric markets. More recently, the Commission issued proposed rules on credit 

reforms (in Docket No. RM10-13-000) at its January 2010 meeting. The proposed 

rules would eliminate any use of unsecured credit in the FTR auctions. The proposed rules also would require shorter settlement cycles in all transactions, require 

minimum creditworthiness criteria for market participation, clarify when a market 

administrator may invoke ‘‘material adverse change’’ to require additional security, 

and shorten the grace period for curing collateral posting requirements. 

Further, the Commission has opened an inquiry in Docket No. RM10-12-000 into 

whether to require quarterly reporting of all bilateral (secondary) sales of FTRs. Reporting such sales of FTRs could increase the transparency of the FTR markets. 

c. Finally, aren’t public power entities often legally prohibited from providing 

cash as collateral? 

Answer. In the RTO/ISO markets, secured credit is obtained through either a 

posting of cash as security or a letter of credit from a creditworthy bank with offices 

in the United States. Traditionally, public power entities have often not been required to post collateral. As mentioned in response to the previous question, the 

Commission’s proposed rule would eliminate the ability to post unsecured credit for 

FTRs, though we seek comments on whether some market participants, like public 

power entities, should be exempt from the new proposed rule. 

Question 6. Are FTRs ‘‘standardized’’ contracts or are these customized products 

that are not fungible? 

Answer. Each FTR is path-specific and its value reflects the difference between 

the price of power at two particular locations on the grid. There are thousands of 

paths in each market, each with its own unique risk profile. FTRs are not fungible 

in the way that instruments traded on NYMEX are fungible. Fungibility allows 

traders to create new contracts and trade in and out of existing ones because each 

new contract is exactly the same. Because only the RTO/ISO issues FTRs, and does 

so only in a manner consistent with the physical constraints on the system during 

defined auction periods, individual traders cannot decide to create new FTRs outside 

of the RTO auctions. 

RESPONSES OF JON WELLINGHOFF TO QUESTIONS FROM SENATOR STABENOW

Question 1. The House bill directs FERC and the CFTC to create memorandum 

of understanding for the process of sharing information to avoid duplicative regulation. It also gives the CFTC the authority to exempt FTRs from its regulation only 

if the CFTC determines that the ‘‘exemption would be consistent with public interest.’’ It directs the CFTC to ‘‘not unreasonably deny any request made by the Federal Energy Regulatory Commission for such an exemption.’’ 

If this provision were to pass into law and the agencies could not agree on an 

MOU in a timely manner or a lack of clarity in the jurisdiction remained, I am concerned this may affect energy prices. In a state like Michigan our manufacturers 

and households cannot afford undue burdens like this and I am worried uncertainty 

leads to an increase in prices. Do you agree with this and if so do you think that 

keeping energy costs low via energy markets qualifies as within the ‘‘public interest’’? 

Answer. Lack of clarity about who regulates the energy markets can reduce the 

willingness of investors to support new energy infrastructure or increase the return 

on capital they seek for making investments in the face of such uncertainty. Both 

of these outcomes could hurt consumers. Legislation clearly preserving FERC’s jurisdiction would avoid this uncertainty, and is far preferable to a statutory requirement that two agencies resolve the issue by agreement. Furthermore, while the Federal Power Act’s concept of ‘‘public interest’’ clearly includes keeping energy costs 

reasonable for consumers, the Commodity Exchange Act’s reference to ‘‘public interest’’ is not parallel. The Commodity Exchange Act focuses on whether markets operate fairly and orderly but, unlike the Federal Power Act, contains no obligation to 

consider the reasonableness of rates to customers. 

Question 2. During his testimony, Mr. Gensler pointed to the Amaranth case as 

a good example of the two agencies working together. Please describe the situation, 

each agency’s role and if there is anything you would do differently. 

Answer. Shortly after FERC first observed the anomalous trading activity by Amaranth and initiated its investigation, it informed the CFTC. Thereafter, the agencies worked well together in evaluating and investigating the matter. Each agency 

brought a case against Amaranth, though there were substantive differences in the 

two cases. FERC has a Memorandum of Understanding with the CFTC under which 

FERC requests, through the CFTC, data and information from the CFTCdesignated 
73 

‘‘Contract Markets’’ such as NYMEX. While FERC retains the ability to acquire 

such information directly, through informal request or Commission subpoena, FERC 

has respected the role of the CFTC as the exclusive day-to-day regulator of the market and has used this process consistently even though it is not as efficient as seeking the information directly. The CFTC did take a position in the courts that FERC 

did not have jurisdiction over an Amaranth-type case. FERC strongly disagrees with 

that position, and depending on how the cases progress, the courts may resolve that 

matter. 

Question 3. If the CFTC determines that FTRs are futures contracts how would 

that change your regulation of the market? Are there areas where you see regulation of the market could be improved? If so, is it possible for FERC to address them? 

Would legislation be required? 

Answer. If the CFTC determines that FTRs are futures contracts, the CFTC 

would then decide whether to impose its regulatory requirements on FTRs or exempt them from CFTC regulation. If the former, the CFTC would assert that its 

jurisdiction is exclusive, and FERC could be precluded from regulating FTRs. 

FERC considers on an ongoing basis whether improvements are warranted in 

RTO/ISO markets. For example, two months ago, FERC proposed (in Docket No. 

RM10-13-000) strengthening the credit requirements in RTO/ISO markets. FERC 

will consider all comments received on this proposal before taking final action. At 

the same time, FERC opened an inquiry in Docket No. RM10-12-000 on whether to 

require comprehensive reporting of bilateral (secondary) sales of FTRs. FERC has 

comprehensive authority to regulate the rates, terms and conditions of RTO/ISO 

markets, and does not see a need for additional legislation, except for the purpose 

of preserving FERC’s jurisdiction. 

Question 4. Please share your views on whether the mandatory reporting of energy commodity contracts to regulated swap or derivative repositories is a regulatory solution that would meet the public policy goals of increasing market transparency, mitigating systemic risk, and providing price transparency, without hindering the ability for end-users to hedge their commercial risk or increasing costs 

to consumers. 

Answer. I do not have a position on the mandatory reporting of energy commodity 

contracts to regulated swap or derivative repositories, but FERC has imposed extensive reporting requirements in the wholesale power markets. FERC currently requires all companies authorized to sell physical power under its jurisdiction to report their sales in detail on a quarterly basis. These reports include counterparty 

information, price, quantity and location, and FERC makes this information publicly 

available. FERC has adopted this requirement to ensure that the public has access 

to the rates charged by power sellers in compliance with the Federal Power Act and 

as a mechanism to aid transparency in furtherance of the Commission’s statutory 

mission to ensure just and reasonable rates. 

RESPONSE OF MICHAEL W. HENDERSON TO QUESTION FROM SENATOR BINGAMAN

Question 1a. Your testimony notes that the Southwest Power Pool (SPP) is ‘‘currently evaluating and designing how it will develop an FTR market,’’ which is one 

of many possible changes to the SPP market. What is driving SPP and its market 

participants to evaluate changes to its current market design? 

Answer. The desire of SPP’s members to implement a day-ahead energy and ancillary services market is primarily driven to realize an annual savings of one hundred 

million dollars ($100,000,000) identified in a cost/benefit study. 

Question 1b. Has uncertainty surrounding regulation of FTRs influenced that 

evaluation in any way? If yes, how? 

Answer. Our evaluation thus far has assumed FTRs will continue to be regulated 

by FERC as a cost allocation vehicle not as a separate market commodity. If financial reform legislation were to create uncertainty, the stakeholders in SPP would 

have to reconsider whether the move to an FTR market still provided consumers 

with net benefits. In other words, the uncertainty could potentially deny consumers 

in SPP the opportunity to save $100 million. 

RESPONSES OF MICHAEL W. HENDERSON TO QUESTIONS FROM SENATOR MURKOWSKI

Question 1a. Is there currently a regulatory gap we’re trying to plug for electric 

market mechanisms like Financial Transmission Rights? 

Answer. No, in my opinion, there is no regulatory gap for those mechanisms. Such 

mechanisms, like congestion rights, are an inherent part of the cost of wholesale 

electric sales and transmission service regulated by FERC. 
74 

Question 1b. Aren’t FTRs already regulated by FERC through its review and approval of RTO tariffs? 

Answer. Yes. 

Question 2. Why can’t utilities clear their derivative transactions on exchanges 

like other standardized commodities? 

Answer. FTRs are not ‘‘standardized commodities’’. FTRs are unique and noninterchangeable congestion reservation rights used by FERC to allocate cost among 

transmission users. Many of the other hedging transactions used by cooperatives are 

similarly difficult to treat as ‘‘standardized commodities.’’ They are used to provide 

carefully tailored hedges for physical transactions that provide for delivery of different volumes of energy for each of the 8760 hours of the year at thousands of distinct delivery points. Even those hedging transactions that might be susceptible to 

standardization are currently being traded between sophisticated counterparties 

with individualized credit requirements that recognize the different business structures, levels of liquidity, and sources of security specific to different electric utilities. 

Mandatory clearing on exchanges would force those ‘‘round’’ end-user transactions 

into ‘‘square’’ holes designed for financial counterparties. Without providing the 

markets any greater protection, such an approach could inevitably increase the cost 

of hedging for utilities and thus raise either the cost of power or the volatility of 

prices for retail electric consumers. 

Question 3. You testified that the cost for the Arkansas Electric Cooperative Corporation of providing transmission service to rural Arkansans increased by over 60% 

from 2004 to 2009—that’s about a 10% increase per year. Would these costs have 

been even higher without the use of hedging instruments like Financial Transmission Rights (FTR) and Congestion Revenue Rights (CRR)? 

Answer. FTRs and CRRs are not currently part of the SPP market. Congestion 

costs are currently part of the transmission tariffs set by FERC. If FTRs/CRRs are 

introduced in the SPP as a separate commodity, they should only serve to attempt 

to fine tune the allocation of congestion cost among users. But, as noted above, studies indicate that, collectively, all consumers within the SPP footprint could save as 

much as $100 B if the RTO develops FTR markets. Those savings are at risk if financial reform legislation creates regulatory uncertainty by imposing duplicative 

layers of regulation on those markets. 

Question 4a. What would CFTC regulation of these financial products like FTRs 

and CRRs mean to your consumers? 

Answer. First, if financial reform legislation imposes duplicative layers of regulation on FTRs and FTR markets, the SPP might choose not to form those markets, 

denying consumer’s significant potential savings. If the SPP does establish the FTR 

markets and they are regulated by both the FERC and the CFTC, there could be 

two different regulators defining what an FTR ‘is,’’ who can trade in FTRs, how they 

are traded, and what the credit requirements are for trading the FTRs. Those rules 

could conflict, raising the specter that a utility that complies with its FERC tariff 

could be in violation of CFTC regulations and vice versa. That uncertainty will 

make it extremely different for utilities to use FTRs to hedge their risks in the SPP 

market. Moreover, FERC can currently take all transmission costs into consideration when setting transmission tariffs. If a portion of transmission costs are regulated outside of FERC (such as by the CFTC), the opportunity for financial and nonutility entities to extract value or inflict additional cost to transmission users could 

exist. Regulation by CFTC could open FTRs and CRRs values to more volatility and 

resulting in less stable transmission cost. More volatile cost generally will result in 

more volatile financial results and ultimately more expensive capital cost as well as 

incurring duplicative regulatory costs for the transmission users. 

Question 4b. Would the costs associated with clearing prohibit the use of these 

hedging instruments, thereby leaving consumers exposed to volatile prices, or would 

you simply be forced to pass on the increased costs to the end-user? 

Answer. The cost of clearing would not technically prohibit the use of these hedging instruments as long as the costs are included in FERC approved tariffs. However, as an electric cooperative, any additional costs are absorbed by our member 

consumers. Thus we face a Hobson’s choice. We must either charge our customers 

more for power to cover the higher cost of hedging, or if those added costs are greater than the value of the hedge, then we will be unable to hedge our market risks 

and will instead expose our consumers to much greater price volatility. 

Question 4c. What are the problems associated with cash collateral requirements? 

Answer. The two primary problems with collateral calls are the cost of providing 

a credit facility and the availability of a credit facility. If the SPP used FTRs and 

CRRs during the last quarter of 2008, AECC would have had to pay large fees for 

a credit facility if it could even find a financial institution that could provide one. 
75 

These additional costs are borne by AECC’s rural member consumers with no service benefit. 

Question 5. You noted in your testimony that all components of transmission costs 

should be regulated by a single entity. What are the practical problems of having 

two federal regulators? 

Answer. Multiple regulators require duplicative compliance and reporting by market participants. Duplicative compliance efforts will drive up the cost for transmission users. FERC as regulator of the physical transmission service would not be 

in a position to set a tariff to include the market losses or gains incurred from transactions in a financial market. Different objectives of multiple regulators can result 

in conflicting rules making compliance difficult or impossible to attain and potentially subjecting the market participant to penalties from one regulator merely because they complied with the rules imposed by the other regulator. 

Question 6. Do you believe that advanced power sales should be categorized as 

futures transaction, making them subject to the CFTC’s exclusive jurisdiction? 

Answer. No. Advanced power sales are not commodities in my opinion. A significant number of committed transactions in many markets take place on an advance 

basis. Advanced power sales should be viewed in a like manner as transactions for 

non-refundable hotel reservations or airline tickets purchased days before actual 

travel or advanced purchase of entertainment tickets before the event. 

In the 2005 Energy Policy Act (EPAct), Congress recognized the need for load 

serving entities to plan long-term to meet the needs of our consumers. Rather than 

providing for transmission rights to be treated as a traditional commodity, Congress 

required in new Federal Power Act (FPA) sec. 217(b)(4) that FERC exercise its authority under the FPA to ensure that load serving entities (like electric cooperatives) 

have access to the long-term transmission rights they need to meet the long term 

needs of their consumers. Congress recognized in this section that the electric utility 

industry is a capital intensive industry in which we rely on generation and transmission infrastructure that can take 30 years to pay off and that can be useful for 

another 40 years after that. Congress understood when they drafted EPAct that we 

cannot plan, finance, build, and maintain that infrastructure based entirely on spot 

market purchases and sales. Instead, we must contract for both power resources and 

the transmission capacity needed to deliver that power to load months, years, and 

even decades ahead. Those contracts are supported financially by the legal obligation of millions of retail consumers to pay for the power that they use to heat their 

homes, run their production facilities, and pump water to irrigate their crops. EPAct 

is consistent with the federal government’s long-standing position that electricity is 

as an essential service imbued with the public interest rather than as a commodity 

like soybeans or pork bellies. That is why the physical market for electricity has 

long been closely regulated by economic regulators, including the Federal Power 

Commission and its successor the FERC and state PUCs, rather than the CFTC. 

RESPONSES OF GARY GENSLER TO QUESTIONS FROM SENATOR BINGAMAN

Question 1. The CFTC is currently examining whether Financial Transmission 

Rights (FTRs) should be considered ‘‘futures’’ under the Commodities and Exchange 

Act. Is the CFTC currently examining any other FERC-approved instruments or 

products that are available pursuant to Regional Transmission Organization (RTO) 

or Independent System Operator (ISO) tariffs? If so, which instruments or products 

and why? 

Answer. The CFTC has not taken any action to regulate the FTR market which 

is currently regulated by the Federal Energy Regulatory Commission (FERC). Additionally, the CFTC is not seeking to regulate other current RTO products. 

In 2000, PJM Interconnection, LLC contacted staff of the Commodity Futures 

Trading Commission (CFTC) in regard to a possible exemption from the Commodity 

Exchange Act (CEA) for PJM’s FTR market due to similarities between FTRs and 

futures contracts. In addition, some information has been supplied by PJM to the 

CFTC staff in the intervening years. In order to address potential concerns with respect to the authorities of the two agencies, section 3009 of the House passed 

version of H.R. 4173 requires cooperation between them. Section 3009 specifies: 

SEC. 3009. MEMORANDUM. 

(a)(1) The Commodity Futures Trading Commission and the Federal Energy 

Regulatory Commission shall, not later than 180 days after the date of the enactment of this section, negotiate a memorandum of understanding to establish 

procedures for— 
76 

(A) applying their respective authorities in a manner so as to ensure effective and efficient regulation in the public interest; 

(B) resolving conflicts concerning overlapping jurisdiction between the 

two agencies; and 

(C) avoiding, to the extent possible, conflicting or duplicative regulation. 

(2) Such memorandum and any subsequent amendments to the memorandum 

shall be promptly submitted to the appropriate committees of Congress. 

(b) The Commodity Futures Trading Commission and the Federal Energy 

Regulatory Commission shall, not later than 180 days after the date of the enactment of this section, negotiate a memorandum of understanding to share information that may be requested where either Commission is conducting an investigation into potential manipulation, fraud, or market power abuse in markets subject to such Commission’s regulation or oversight. Shared information 

shall remain subject to the same restrictions on disclosure applicable to the 

Commission initially holding the information. 

Question 2. Does the CFTC believe it should be regulating FERC-approved instruments or products offered by public utilities that are not members of an RTO or 

ISO? If so, which instruments or products and why? 

Answer. The CFTC is not reviewing FERC-approved instruments or products that 

are offered by public utilities that are not members of an RTO or ISO. 

Question 3. Does the definition of swaps or futures contained in H.R. 4173, if enacted, require the CFTC to regulate any FERC-approved instruments or products 

other than FTRs? 

Answer. H.R. 4173, the Wall Street Reform and Consumer Protection Act of 2009, 

provides for the regulation of the previously unregulated Over-The-Counter (OTC) 

derivatives market including establishing requirements for OTC dealers, requiring 

centralized clearing where appropriate and providing for increased transparency of 

the OTC market. Section 3009 of H.R. 4173 as passed by the House, preserves the 

jurisdiction of both FERC and the CFTC. 

Question 4. As was discussed at the March 9th hearing, FERC and the CFTC are 

charged with different missions. The standard the CFTC applies in its regulation 

addresses the orderly functioning of markets that are not manipulated. Unlike 

FERC, the CFTC does not have the authority to examine the reasonableness of 

rates. How would the CFTC apply its mission to the markets for FTRs or other 

products offered pursuant to RTO and ISO tariffs? Has the CFTC analyzed how a 

shift in the regulatory objective would affect FTR markets and how that could ultimately affect ratepayers? 

Answer. The CFTC’s mission is to protect market users and the public from fraud, 

manipulation, and abusive practices related to the sale of commodity and financial 

futures and options, and to foster open, competitive, and financially sound futures 

and option markets. In pursuing its mission the CFTC routinely cooperates with 

other agencies that have jurisdiction over cash markets for the underlying commodities. Such agencies include the Department of Agriculture, the Securities and Exchange Commission, the Department of the Treasury, the Federal Reserve Board, 

the Department of Energy, and FERC. In fact, the CFTC and the FERC currently 

have a formal memorandum of understanding (MOU) regarding the sharing of information and the confidential treatment of proprietary energy trading data. 

The CFTC recognizes FERC’s authority and responsibility to assure that consumers pay just and reasonable electricity rates and has no intention of infringing 

on FERC’s rate setting role. 

Question 5. In his testimony, Vincent Duane from PJM interconnection stated 

that the FTR is inextricably linked to locational priced energy markets. How could 

FERC and the CFTC fulfill their respective missions if they individually regulate, 

according to different standards, two ‘‘inextricably linked’’ products? 

Answer. Though the CFTC has exclusive jurisdiction over the futures markets, it 

coexists and routinely cooperates with other agencies that have jurisdiction over 

cash markets for underlying commodities. While the missions of the two agencies 

are not identical, any differences can be resolved The two agencies currently have 

Memoranda of Understanding in place to formalize our relationship. In addition, 

Congress has provided the CFTC with broad exemptive authority which can be used 

to provide regulatory clarity where appropriate and in the public interest. 

Question 6. The CFTC is working with Congress to bring comprehensive regulation to the over-the-counter derivatives marketplace. Chairman Gensler has stated 

that regulatory reform should ensure that clearable swaps are submitted to and settled through central clearinghouses. How does the CFTC define ‘‘clearable swaps’’? 

Answer. Clearable swaps are those sufficiently standardized to allow clearing. The 

House of Representatives addressed the issue of which swaps should be cleared in 
77 

Section 3103(j) of H.R. 4173, the Wall Street Reform and Consumer Protection Act 

of 2009, by providing that, in general, a swap should be cleared if a clearing house 

accepts it for clearing and the CFTC has determined that the swap is required to 

cleared, by taking into account: 

‘(I) The existence of significant outstanding notional exposures, trading liquidity and adequate pricing data. 

‘(II) The availability of rule framework, capacity, operational expertise and resources, and credit support infrastructure to clear the contract on terms that 

are consistent with the material terms and trading conventions on which the 

contract is then traded. 

‘(III) The effect on the mitigation of systemic risk, taking into account the size 

of the market for such contract and the resources of the derivatives clearing organization available to clear the contract. 

‘(IV) The effect on competition, including appropriate fees and charges applied 

to clearing. 

‘(V) The existence of reasonable legal certainty in the event of the insolvency 

of the relevant derivatives clearing organization or 1 or more of its clearing 

members with regard to the treatment of customer and swap counterparty positions, funds, and property. 

The Senate-passed bill includes similar standards. 

Question 7. There are several key attributes of FTRs: 

a. The supply of FTRs is finite, limited by the physical characteristics of the 

transmission system. 

b. Before any FTRs are sold in an auction, RTOs and ISOs allocate a certain 

number of FTRs to load serving entities (LSEs) 

c. The period of time between auctions can be quite long 

Do these attributes, individually or in some combination, distinguish FTR markets from commodity markets currently regulated by the CFTC? If yes, can the 

CFTC identify how it might regulate markets with such attributes? Is the CFTC 

prepared to regulate such markets? 

Answer. While each futures market the CFTC regulates and its underlying cash 

market are in some way distinctive, the CFTC has neither taken a position on how 

FTRs should be regulated, nor sought to regulate them. 

Question 8. Given the long periods of time between auctions for FTRs, how could 

any clearing entity mark positions to a reliable and transparent market price? 

Answer. In a response to an invitation from FERC Chairman Wellinghoff to the 

CFTC to comment on the FERC Notice of Proposed Rulemaking on Credit Reforms 

in Organized Wholesale Electric Markets (FERC NPRM), on March 29, 2010, the 

CFTC staff of its Division of Clearing and Intermediary Oversight addressed this 

issue in footnote 11: 

In general, commodity futures and options markets operate continuously, 

thus providing reliable pricing for frequent settlements. Staff understands 

that FTR markets operate less continuously, with auctions occurring at, 

e.g., monthly intervals. Staff believes that it would be best practice for each 

RTO or ISO to operate daily FTR auctions, which would produce the most 

accurate pricing. However, staff understands that, due to the nodal nature 

of FTRs, such daily auctions may be subject to liquidity challenges. [citation 

omitted] Therefore, staff recommends that each RTO or ISO be permitted 

to mark FTR positions to models, provided that such models are externally 

validated. Another alternative may be for each RTO or ISO to mark FTR 

positions to quotes from the secondary (i.e., bilateral) FTR markets. However, the feasibility of such alternative depends on the depth and liquidity 

of such secondary FTR markets. 

Question 9. Individual FTRs are defined according to two specific points on the 

transmission system: a source point (e.g. generator) and a sink point (e.g. load location). According to PJM there over 60 million possible transmission paths that could 

define individual FTRs. Does the CFTC believe that an FTR defined by a particular 

source-sink combination is distinct from an FTR with a different source-sink combination, assuming they cover identical periods of time? Are these FTRs fungible 

(e.g., could they be netted against one another in the clearing process)? Why? 

Answer. The CFTC has not taken a position on the defining characteristics of 

FTRs or whether or not one FTR position could be used to offset another. 

Question 10. Has the CFTC analyzed how ratepayers would be affected if 1) FTRs 

with different source-sink combinations were deemed to be distinct and 2) FTR markets were subject to clearing requirements? 
78 

Answer. No. 

Question 11. In January of this year, FERC issued a Notice of Proposed Rulemaking that would require participants to submit cash collateral to the RTOs to 

participate in the FTR markets. How does this proposal compare to the regulatory 

regime that would result from the CFTC finding that FTRs are subject to its jurisdiction? 

Answer. The CFTC has not considered what type of regulatory regime would result from a CFTC finding that FTRs are subject to its jurisdiction as the CFTC has 

not taken a position on whether FTRs are subject to its jurisdiction. As stated in 

the answer to question number 9, Chairman Wellinghoff invited the CFTC to comment on the FERC NPRM and staff of the CFTC’s Division of Clearing and Intermediary Oversight did so on March 29, 2010. A copy of the comment letter is included is an attachment. 

As page 4 of the comment letter states, ‘‘[s]taff fully supports FERC’s proposals 

to require each RTO or ISO.to eliminate unsecured credit in FTR markets. . .’’. 

RESPONSES OF GARY GENSLER TO QUESTIONS FROM SENATOR MURKOWSKI

Question 1. Is there currently a regulatory gap we’re trying to plug for electricity 

market mechanisms like Financial Transmission Rights? Aren’t FTRs already regulated by FERC through its review and approval of RTO tariffs? 

Answer. In 2008 the financial regulatory system failed the American public. We 

must now do all we can to ensure that it does not happen again. While more than 

a year has passed and the system appears to have stabilized, we cannot relent in 

our mission to vigorously address weaknesses and gaps in our regulatory structure. 

One of the most significant gaps is the lack of oversight of the OTC derivatives market. As I stated in my written testimony, ‘‘wholesale statutory exemptions preventing the application of any CFTC regulation—including the regulation of futures 

contracts, swaps contracts, clearing or exchange trading—for any instrument or 

market that is regulated by the FERC undermine the effectiveness of comprehensive 

reform. Congress should avoid any bright-line exemption that runs the risk of creating the next regulatory loophole.’’... 

‘‘History demonstrates that bright-line statutory exemptions or exclusions granted 

at one point in time can have unintended consequences and often fail to adequately 

account for subsequent developments. Markets evolve rapidly. What may seem like 

a carefully crafted exclusion today can become a significant and problem-filled loophole tomorrow. When the Enron loophole was included in statute in 2000, electronic 

trading facilities were in their infancy. By the time Congress addressed the loophole 

as part of the Farm Bill in 2008, the unregulated electronic trading of natural gas 

swaps was on a par with the trading of natural gas futures on the regulated market.’’ Congress can assure comprehensive regulation of the derivative market and 

should address concerns of overlap by providing regulatory agencies with flexibility 

such as implimentive authority. 

Question 2. According to former FERC Chairman Joe Kelliher, who is testifying 

today on the second panel, energy providers do not pose a systemic risk to the 

broader economy. Instead, the entire commodities market is less than 1 percent of 

the global OTC derivatives markets, and the energy commodity portion is yet a fraction of that one percent. 

Do you agree that these electricity market instruments do not pose the kind of 

systemic risk Congress is trying to address in financial reform regulation? If so, isn’t 

this a good case for striking a reasonable balance. 

Answer. As mentioned above, the CFTC has neither taken a position on how FTRs 

should be regulated, nor sought to regulate them. I do not believe it is appropriate 

to carve out from regulation any particular financial instrument. The agencies can 

strike a reasonable balance and modify that balance to take into account evolving 

changes in the marketplace without requiring Congress to adopt changing legislation over the years. In fact, Congress has provided the agencies with adequate tools 

to work cooperatively. The CEA provides the CFTC with authority to exempt instruments and markets from its regulations if it is determined to be in the public interest to do so. OTC derivatives reform should extend this exemptive authority with 

the CFTC’s oversight of the swaps market. Any potential overlaps in oversight can 

be addressed through memoranda of understanding and other cooperative working 

relationships between the two agencies. Pending legislation also should maintain 

the FERC’s anti-manipulation enforcement authorities under Section 222 of the 

Federal Power Act and Section 4A of the Natural Gas Act. 

Question 3. There’s a concern that under the new financial reform legislation the 

RTOs and ISOs themselves could become subject to the CFTC’s jurisdiction as ‘‘derivative clearing organizations.’’ Is that appropriate? If RTOs were subject to the 
79 

CFTC’s exclusive jurisdiction, what additional rules and regulations would be required? 

Answer. The CFTC has not taken a position on whether RTOs and ISOs are or 

would become subject to CFTC jurisdiction as derivatives clearing organizations. As 

passed by the House, Section 3102(a) of H.R. 4173, the Wall Street Reform and Consumer Protection Act of 2009, fully preserves FERC’s authority over RTOs and 

ISOs: 

‘(H)(i) Nothing in this Act shall limit or affect any statutory authority of the 

Federal Energy Regulatory Commission with respect to an agreement, contract, 

or transaction that is— 

‘(I) not executed, traded, or cleared on a registered entity or trading facility; and 

‘(II) entered into pursuant to a tariff or rate schedule approved by the 

Federal Energy Regulatory Commission. 

Question 4. Chairman Gensler, you testified that standardized derivatives should 

be cleared and exchange traded. Do you believe that FTRs traded through an RTO 

are ‘‘standardized’’? If you do, does this mean that in your opinion the CFTC should 

determine that FTRs are ‘‘requirements to be cleared’’? Pursuant to the House 

passed legislation, H.R. 4173, would you consider FTRs to be ‘‘swaps’’? 

Answer. The CFTC has not taken a position on whether FTRs are swaps under 

H.R. 4173, the Wall Street Reform and Consumer Protection Act of 2009. Additionally, The CFTC has not taken a position on the defining characteristics of FTRs. 

Question 5. Do you believe that advanced sales of power—whether in the organized wholesale markets or the traditional bilateral ones—are ‘‘futures’’ transactions 

that would subject them to the CFTC’s exclusive jurisdiction? Would you consider 

them ‘‘swaps’’? 

Answer. Forward contracts, that is, cash contracts where shipment or delivery is 

deferred for commercial convenience or necessity, have been excluded from federal 

regulation of futures transactions since 1922. 

Question 6. Please describe the additional rules and regulations that will result 

from the CFTC’s oversight of FTR products—in particular the cash collateral and 

margin requirements. Has the CFTC examined the impact on customers of requiring 

energy end-users to clear OTC derivatives? 

Answer. As mentioned above, the CFTC has neither taken a position on how FTRs 

should be regulated, nor sought to regulate them. The CFTC staff has not examined 

the impact on customers of requiring energy end-users, or other end-users, to clear 

OTC derivatives. Central clearing of as many OTC derivatives as possible is desirable to improve financial integrity and inter-connectiveness of the OTC market. 

With respect to OTC derivatives, as stated in my written testimony: 

‘‘Some corporations have expressed concerns regarding posting the collateral required to clear a contract. While this is a legitimate public policy debate, I believe that the public is best served by lowering risk to the system 

as a whole. An exemption from clearing for this large class of transactions 

would allow dealers to keep significant risk on their books—risk that could 

reverberate throughout the entire financial system if a bank fails. Further, 

it is not clear that posting collateral necessarily increases costs to end 

users, since dealers charge corporations for credit extensions when the corporations do not post margin.’’ I would further add that, although it is not 

certain that posting collateral would necessarily increase costs to end users, 

it is certain that requiring dealers to post collateral would protect end users 

and their customers. Bringing OTC transactions into clearing would impose 

collateral requirements on dealers. Credit requirements are used to protect 

participants from the effects of defaults by other participants. 

Question 7. Does the CFTC view electricity as a necessary commodity? 

Answer. Yes. 

Question 8. Shouldn’t FERC’s regulatory priorities be afforded some deference? 

Answer. Yes. The FERC oversees important aspects of the energy markets, including monitoring natural gas pipelines and regulating for just and reasonable wholesale electricity rates and interstate transmission service of electricity, while the 

CFTC oversees futures markets and certain electronic trading facilities for natural 

gas and electricity derivatives. As stated above in answer to question two, the Congress has provided the CFTC and the FERC with the authorities necessary to coexist and cooperate in the public interest and both agencies have done so over the 

years. Further directives to the two agencies are contained in Section 3009 of H.R. 
80 

4173, the Wall Street Reform and Consumer Protection Act of 2009, as passed by 

the House of Representatives. 

Question 9. Does the CFTC believe it has the authority to regulate wholesale electricity markets and transactions that are already subject to a FERC-approved tariff? 

Answer. The CFTC oversees the futures markets in electricity and natural gas 

whether they trade on NYMEX or the Nodal Exchange or the 

IntercontinentalExchange. We regulate futures exchanges, clearinghouses, other 

intermediaries to ensure the markets work efficiently, there’s integrity to markets 

and they’re free of fraud, manipulation. 

RESPONSES OF GARY GENSLER TO QUESTIONS FROM SENATOR STABENOW

Question 1. The House bill directs FERC and the CFTC to create memorandum 

of understanding for the process of sharing information to avoid duplicative regulation. It also gives the CFTC the authority to exempt FTRs from its regulation only 

if the CFTC determines that the ‘‘exemption would be consistent with public interest.’’ It directs the CFTC to ‘‘not unreasonably deny any request made by the Federal Energy Regulatory Commission for such an exemption.’’ 

Answer. Yes, that is correct and the CFTC historically as the derivatives regulator 

has cooperated with other agencies with jurisdiction over underlying commodities. 

Question 2. If this provision were to pass into law and the agencies could not 

agree on an MOU in a timely manner or a lack of clarity in the jurisdiction remained, I am concerned this may affect energy prices. In a state like Michigan our 

manufacturers and households cannot afford undue burdens like this and I am worried uncertainty leads to an increase in prices. Do you agree with this and if so do 

you think that keeping energy costs low via energy markets qualifies as within the 

‘‘public interest’’? 

Answer. I believe the two agencies will be able to reach an agreement in a timely 

manner Congress directed that the CFTC and the FERC complete an earlier MOU 

on the sharing of confidential information within six months of the Energy Policy 

Act’s August 8, 2005, effective date. That MOU was signed on October 12, 2005— 

well in advance of the deadline. At the time, the CFTC Chairman said, ‘‘This MOU 

will result in a more effective and efficient working relationship with FERC. It will 

enable both agencies to work actively to assure the price integrity of the markets 

for natural gas and other energy products.’’ The FERC Chairman said, ‘‘The fact 

that we have this agreement with the CFTC four months ahead of schedule is a 

clear sign of the enhanced cooperation and coordination between our two agencies. 

This means the agreement is in place well before the winter heating season, when 

already stressed energy prices will require vigilance. This agreement will contribute 

to better coordination of enforcement.’’ 

Question 3. During his testimony, Mr. Gensler pointed to the Amaranth case as 

a good example of the two agencies working together. Please describe the situation, 

each agency’s role and if there is anything you would do differently. 

Answer. The CFTC believes it appropriate to refrain from commenting in detail 

on the Amaranth matter while it is still being litigated by FERC. 

Question 4. Please share your views on whether the mandatory reporting of energy commodity contracts to regulated swap or derivative repositories is a regulatory solution that would meet the public policy goals of increasing market transparency, mitigating systemic risk, and providing price transparency, without hindering the ability for end-users to hedge their commercial risk or increasing costs 

to consumers. 

Answer. Bringing transparency to the over-the-counter derivatives marketplace 

would lower costs by implementing a more efficient and publicly available price discovery process. Trade reporting is an important first step toward an increase in 

transparency. To promote public transparency, standard over-the-counter derivatives should be traded on exchanges or other trading platforms. The more transparent a marketplace, the more liquid it is, the more competitive it is, then the 

lower will be the costs for companies that use derivatives to hedge risk. Transparency brings better pricing and lowers risk for all parties to a derivatives transaction. During the financial crisis, Wall Street and the Federal Government had no 

price reference for particular assets—assets that we began to call ‘‘toxic.’’ Financial 

reform will be incomplete if we do not achieve public market transparency. 
(81) 

APPENDIX II 

Additional Material Submitted for the Record 

STATEMENT OF MICHAEL E. BOYD, PRESIDENT, CALIFORNIANS FOR RENEWABLE

ENERGY, INC. (CARE) 

Chairman Bingaman, Ranking Member Murkowski and members of the Committee in behalf of energy and natural gas ratepayers in the West I would like to 

thank you for an opportunity to provide rebuttal testimony to the testimony provided to you by the current Chairman of the Federal Energy Regulatory Commission 

(FERC), Wellinghoff, and the former FERC Chairman, Kelliher, regarding the regulation of over-the-counter (OTC) derivatives, particularly with respect to energy 

markets. I am pleased to testify in support of the Commodity Futures Trading Commission Chairman Gary Gensler testimony. I would like ask for energy consumers 

to be given the opportunity that FERC was unwilling to provide us to be heard by 

the U.S. Senate Committee on Energy and Natural Resources on the adequacy of 

FERC’s consumer protection or the lack thereof. 

CARE was the first consumer, environmental, and social-justice, non-profit (IRS 

501(c)(3) Tax Exempt) corporation to blow the whistle on energy market manipulation by the likes of Enron, in our October 6, 2000 complaint to the FERC under 

Docket EL01-2 et al. alleging the rolling blackouts in the San Francisco Bay Area 

on June 14th and 15th 2000 where contrived by energy producers in concert with 

the California Independent System Operator Board of Governors to drive up prices 

and justify construction of more fossil-fuel burning power plants in California. 

CARE will not give up on the return of seventy one billion dollars in overcharges 

by power generators public and private, and cancellation of forty three billion dollars in long-term energy contracts negotiated by Governor Davis in secret that resulted from these, and other market manipulations. 

CARE is a party and an active participant in those proceedings related to the 

2000-1 western energy crisis. The FERC decisions addressing the 2000-1 western 

energy crisis did not hold hearings settlement negotiations or other proceedings that 

included the affected ratepayers. CARE’s efforts were the only direct ratepayer participation. All the other parties to the proceedings were regulated utility companies, 

energy commodity traders, governmental ‘‘non-public utilities’’ and state and federal 

government agencies that implemented the policies and practices leading to the energy crisis. 

SHIFTING JURISDICTION OVER ENERGY MARKETS FROM FERC TO THE CFTC COULD IMPAIR FERC’S ABILITY TO PROTECT CONSUMERS FROM EXCESSIVE ENERGY RATES IS

NONSENSE

The Commodity Futures Trading Commission (CFTC) regulates certain financial 

derivatives under existing law, and would regulate additional financial derivatives 

under H.R. 4173, the Wall Street Reform and Consumer Protection Act of 2009 includes some energy derivatives (futures). 

Chairman Wellinghoff would have the Committee believe the FERC and the 

CFTC have different missions claiming ‘‘FERC is a rate regulator and ensures that 

rates charged to energy customers are just and reasonable. FERC also approves and 

enforces electric reliability standards. The CFTC seeks to ensure that markets generally operate fairly and orderly, but has neither the authority nor the expertise to 

ensure the reasonableness of rates or oversee reliability of energy supplies. Shifting 

jurisdiction over energy markets from FERC to the CFTC could impair FERC’s ability to protect consumers from excessive energy rates, an especially important consideration during a recession. Similarly, expanding the CFTC’s authority in FERC-regulated markets could limit FERC’s ability to police against market manipulation in 

energy markets. [SIC]’’ [FERC Testimony at 1] 
82 

1See http://elibrary.ferc.gov/idmws/common/opennat.asp?fileID=11313181 

2San Diego Gas & Electric Co. v. Sellers of Energy and Ancillary Serv., 93 FERC ¶ 

61,121(2000); San Diego Gas & Electric Co. v. Sellers of Energy and Ancillary Serv., 102 FERC 

¶ 61,317(2003). 

3See http://www.supremecourtus.gov/opinions/07pdf/06-1457.pdf 

This is nonsense and the Committee needs to look no further than to what FERC 

has done in its handling of the 2000-1 western energy crisis and the recovery of refunds (or lack thereof) for overcharges of seventy one billion dollars to California 

energy ratepayers alone not including those overcharged in the rest of the western 

United States to see FERC does not serve consumers’ interests. 

On October 6, 2000 CARE filed its FERC Complaint in Docket EL01-2 et al. 

against Independent Energy Producers, Inc. and All Sellers of Energy and Ancillary 

Services Into the Energy and Ancillary Services Markets Operated by the California 

Independent System Operator Corporation and the California Power Exchange; All 

Scheduling Coordinators Acting On behalf of the Above Sellers; California Independent System Operator Corporation; and California Power Exchange Corporation 

wherein I asked the ‘‘Commission to rectify unjust and unreasonable prices stemming from the wholesale markets for energy and ancillary services operated by the 

California Independent System Operator (CAISO) and the California Power Exchange (CalPX). CARE requests that the Commission find that wholesale markets 

in California are not currently workably competitive. . .’’ 

Essentially FERC told me to shut-up and go away and electricity customers where 

not welcome at the FERC. But I didn’t, because initially FERC had listed my complaint EL01-2 along with the San Diego Gas and Electric’s (SDG&E’s) complaint 

filed under Docket EL00-95 et al. now called the Refund proceedings which are still 

pending before the FERC and in which CARE is a Party. 

The disdain for which FERC has shown ratepayers is legendary; besides the fact 

that FERC failed to address the loss of ten lives as a direct result of the rolling 

blackouts in the San Francisco Bay Area on June 14th and 15th 2000 contrived by 

energy producers in concert with the CAISO Board of Governors, the FERC issued 

its April 19, 2007 Order Dismissing Complaint (119 FERC ¶ 61,0581) minimizing the 

impacts of market manipulation as the cause of the energy crisis by stating it was 

the result of a confluence of factors: 

First, it is now well accepted that the 2000-2001 energy crisis in the West 

was the result of a confluence of factors. These factors included: flawed 

market rules; inadequate addition of generating facilities in the preceding 

years; a drop in available hydropower due to drought conditions; a rupture 

of a major pipeline supplying natural gas into California; strong growth in 

the economy and in electricity demand; unusually high temperatures; an increase in unplanned outages of extremely old generating facilities; and market manipulation.2 This was not a situation in which one or a few factors 

stressed the market; rather, it was an unprecedented situation in which numerous adverse events occurred simultaneously to place California and the 

entire West in an electricity crisis that had never before been experienced. 

[119 FERC ¶ 61,058 para 30 p. 9] 

In the seminal US Supreme Court Decision in Morgan Stanley Capital Group v. 

Snohomish County Washington Public Utility District No. 1, 06-14573 the US Supreme Court focused on this minimalist ‘‘confluence of factors’’ argument by the 

FERC by asking the federal courts and the FERC to take another look at the terms 

of long-term wholesale energy contracts several Western utilities signed during the 

2000-1 energy crisis. In the 5-2 opinion, the high court said FERC acted within its 

authority to, in a balanced analysis, determine reasonable wholesale power rates 

but made mistakes in its regulatory review. Under the ruling both the Ninth Circuit 

and FERC must review how conclusions were reached. 

The Court noted at page 11 FERC’s diminutive Order 119 FERC ¶ 61,058: 

That diminishment of the role of long-term contracts in the California 

electricity market turned out to be one of the seeds of an energy crisis. In 

the summer of 2000, the price of electricity in the CalPX’s spot market 

jumped dramatically—more than fifteenfold. See ibid. The increase was the 

result of a combination of natural, economic, and regulatory factors: ‘flawed 

market rules; inadequate addition of generating facilities in the preceding 

years; a drop in available hydropower due to drought conditions; a rupture 

of a major pipeline supplying natural gas into California; strong growth in 

the economy and in electricity demand; unusually high temperatures; an increase in unplanned outages of extremely old generating facilities; and mar-
83 

4 An example of this regulatory revolving door comes from former FERC Chairman Kelliher 

whose March 9, 2010 testimony before the Committee states ‘‘I am Executive Vice President— 

Federal Regulatory Affairs for FPL, Group, Inc. . . .FPL Group is on of the Nation’s largest 

electricity companies. . .’’that shows the revolving door between the FERC and FERC regulated 

entities like FPL. 5See Executive Biography: Mason Willrich, Chair http://www.caiso.com/2449/ 

2449cdbd3b9c0.pdf Executive Biography: Laura Doll http://www.caiso.com/2449/ 

2449cec946570.pdf Executive Biography: Robert Foster http://www.caiso.com/2756/ 

27568ae926390.pdf Executive Biography: Tom Habashi http://www.caiso.com/2756/ 

27568b8f2d830.pdf Executive Biography: Kristine Hafner, Ph.D. http://www.caiso.com/2449/ 

2449ce1d3d5d0.pdf 

ket manipulation.’ CAlifornians for Renewable Energy, Inc. v. Sellers of Energy and Ancillary Servs., 119 FERC ¶ 61,058, pp. 61,243, 61,246 (2007). 

The case involves the terms of numerous power contracts purchased by utilities 

in California, Nevada and Washington State when energy markets were in turmoil. 

At issue in the appeals were long-term agreements that provided power at prices 

set during chaos in the spot electricity markets. After the crisis subsided, the utilities decided the contracts were set at unreasonably high prices that violated federal 

law. 

But the Commission, which oversees wholesale electricity prices, declined to order 

changes in the contracts. Justice Antonin Scalia, in the majority opinion, said FERC 

must engage in a thorough review when it oversees wholesale power contracts. 

‘Balancing the short-term and long-term interests of consumers entails 

difficult judgment calls, and to the extent FERC actually engages in this 

balancing, its reasoned determination is entitled to deference,’ Justice 

Scalia wrote. ‘But FERC cannot abdicate its statutory responsibility to ensure just and reasonable rates through the expedient of a heavy-handed 

presumption.’ 

According to FERC Chairman Wellinghoff ‘‘Congress has recognized FERC’s role 

in ensuring that FTRs help protect utilities and their customers from increases in 

the cost of transmission service. As noted above, Congress in 2005 enacted Federal 

Power Act section 217, requiring FERC to use its authority in a way that enables 

load-serving entities to secure FTRs on a long-term basis for long-term power supply 

arrangements made to meet their customer needs. . .Moreover, Congress has indicated that RTOs and ISOs should be regulated exclusively by FERC. When Congress enacted the Food, Conservation, and Energy Act of 2008 and addressed the 

regulatory gap known as the ‘Enron loophole,’ by giving the CFTC authority over 

‘‘significant price discovery contracts [SPDCs],’’ the Conference Report stated (on 

page 986) that ‘[i]t is the Managers’ intent that this provision [on SPDCs] not affect 

FERC authority over the activities of regional transmission organizations or independent system operators because such activities are not conducted in reliance on 

section 2(h)(3) [of the Commodity Exchange Act].’’’ [FERC Testimony at 6 to 7] 

The Commission’s current ISO/RTO governance processes effectively disenfranchise customers by treating them as a second distinct class while at the same time 

giving so-called ‘‘stakeholders’’ both Commission jurisdictional and non-jurisdictional 

market participants’ control of the ISO/RTO in the very markets that are supposed 

to regulate them. There exists a revolving door between the regulated and the regulators4 under the current ISO/RTO governance structures, since customers exercise 

no oversight over these markets to insure their governing boards protect the customer’s and publics’ interests before those of market participants’ commercial interests they are supposed to regulate. An example of this is the California Independent 

System Operator Corporation’s (CAISO) current Board of Governors who are the appointees of the California Governor; not one who lists any experience representing 

any California customers.5

CARE objects to the California ISO’s current governance, which disenfranchises 

its purported non-profit beneficiaries, who are electricity consumers, and ratepayers 

within the state of California. 

CARE proposes the CAISO board be composed of five directors elected at large 

by its general membership, whom are California’s electricity consumers and ratepayers. The individual receiving the highest number of votes in the annual corporate election is recommended be designated by the title of Independent System 

Operator, who shall act of the corporation’s, President of the Board, Chief Executive 

Officer, and shall act as the official representative of its California membership, in 

the FERC’s other Regional Transmission Organization (RTO)s who are governed in 

the same manner as CARE proposes here for CAISO. Universal ratepayer suffrage 
84 

6State regulatory authority 

7Within the meaning given that term in section 796 (21) of title 16. 

is the key to workably competitive wholesale markets and providing open access to 

transmission services on a non-discriminatory basis. 

CARE proposes that any ratepayer/consumer member of the ISO/RTO receiving 

fifty qualified member signatures on a nomination petition not less than ninety days 

prior to the corporate election be qualified as a nominee for election to the ISO/RTO 

board of directors. Such candidate shall be entitled to a statement of not more than 

500 words, free of charge, which shall be delivered along with the official mail ballot. CARE proposes that such election take place by mail ballot delivered as part 

of the ratepayer/consumer electric utility bill, with a thirty-day polling period for return of ballots in a self addressed postage-paid envelope. Such ballots are recommended be addressed to the appropriate Secretary of State, who is statutorily entrusted to insure the fairness and impartiality of the corporate election process. The 

tallying of the ballots must be open to the members and their corporate director candidates to insure such impartiality. 

CARE views the transmission system as one big integrated transportation service 

that provides services locally, statewide, on the national and international basis 

much like Greyhound’s passenger bus service. But unlike Greyhound this transportation service is for electricity instead of passengers. Like Greyhound’s passenger 

bus service transmission services must be provided on a non-discriminatory basis, 

and in so doing insure that the regulation adopted protects the public’s interest over 

the commercial interests of the provider of services. The Congress for example 

wouldn’t want to put the KKK in charge of the seating arrangement for Greyhound 

buses. Likewise the Congress shouldn’t put market participants in charge of the regulated markets under the FERC’s jurisdiction if they ever want to eliminate discrimination in those markets. 

THE FERC GIVES TOO GREAT A DEFERENCE TO STATE UTILITY COMMISSIONS

Also according to FERC Chairman Wellinghoff; ‘‘State regulators support FERC’s 

jurisdiction in wholesale energy markets instead of a shift of jurisdiction to the 

CFTC. Last month, the National Association of Regulatory Utility Commissioners 

(NARUC) adopted a resolution stating that FERC (and, within ERCOT, the state 

commission) ‘‘should continue to be the exclusive Federal regulator with authority 

to oversee any agreement, contract, transaction, product, market mechanism or 

service offered or provided pursuant to a tariff or rate schedule filed and accepted 

by the FERC. . . .’’ [FERC Testimony at 7] 

The Commission also gives too great a deference to State utility Commissions6

even when there is a clear conflict of interest between their duty to protect the ratepayers from unjust and unreasonable rates with their interests representing the 

state as a wholesale market participant. 

In the Order on rehearing, motion for conditions and compliance filing re Duke 

Energy Trading and Marketing, L.L.C. et al under EL03-152 et al., 126 FERC ¶ 

61,234 (March 19, 2009), the Commission stated: 

CARE cites to 16 U.S.C. § 2602(5), which is a PURPA provision, but our 

action here is pursuant to the FPA and not PURPA. In any event, even if 

CARE’s citation were relevant, CARE is not the only ratepayer advocate. 

For example, the California Public Utilities Commission (CPUC), which is 

one of the California Parties, represents California ratepayers.[] We find 

that the CPUC’s participation in these proceedings belies CARE’s claim 

that ratepayers were excluded.[] [Footnotes not provided] 

CARE is currently challenging this finding before the US Court of Appeals for the 

Ninth Circuit, Docket No. 09-71515. This finding conflicts with the ‘‘factual basis’’ 

for the Commission’s prior rulings on this issue—viz, that the CPUC and CDWR 

are both agents and representatives of the State of California—were not at issue 

or disputed. See Pub. Utils. Comm’n of Cal. v. Sellers of Long Term Contracts, 105 

FERC 61,182 at 51 (2003) (‘‘Complainants, like CDWR, are agents of the State of 

California’’). 

Nor can it be disputed that the CPUC did not negotiate or sign these DWR contracts. What remains at issue, in the remanded cases, is the Commission’s determination that the legal effect of these facts under California law, is that the CPUC 

somehow ‘‘stepped into the shoes’’ of CDWR and therefore must be considered a contracting party. 

These facts have created the irreconcilable conflict between the CPUC’s roles as 

a ‘‘State regulatory authority’’7 to protect the interests of ‘‘electric consumer[s]’’ with 
85 

8TITLE 42 CHAPTER 149 SUBCHAPTER XII Part E § 16471 § 16471. Consumer privacy 

and unfair trade practices (f) Definitions For purposes of this section: (1) State regulatory authority The term ‘‘State regulatory authority’’ has the meaning given that term in section 796 

(21) of title 16. (2) Electric consumer and electric utility The terms ‘‘electric consumer’’ and ‘‘electric utility’’ have the meanings given those terms in section 2602 of title 16. TITLE 16 CHAPTER 46 § 2602 § 2602. Definitions As used in this Act, except as otherwise specifically provided—(1) The term ‘‘antitrust laws’’ includes the Sherman Antitrust Act (15 U.S.C. 1 and following), the Clayton Act (15 U.S.C. 12 and following), the Federal Trade Commission Act (15 

U.S.C. 14[41] and following), the Wilson Tariff Act (15 U.S.C. 8 and 9), and the Act of June 

19, 1936, chapter 592 (15 U.S.C. 13, 13a, 13b, and 21A). (2) The term ‘‘class’’ means, with respect to electric consumers, any group of such consumers who have similar characteristics of 

electric energy use. (3) The term ‘‘Commission’’ means the Federal Energy Regulatory Commission. (4) The term ‘‘electric utility’’ means any person, State agency, or Federal agency, which 

sells electric energy. (5) The term ‘‘electric consumer’’ means any person, State agency, or Federal agency, to which electric energy is sold other than for purposes of resale. 9Michael (the fifth angel) Michael (Hebrew, Greek, Latin, Arabic) is an archangel, one of the 

principal 50 angels in Christian and Islamic tradition. Tradition gives to St. Michael four offices: 

1. To fight against Satan. 2. To rescue the souls of the faithful from the power of the enemy, 

especially at the hour of death. 3. To be the champion of God’s people, the Jews in the Old Law, 

the Christians in the New Testament, the Islamic tradition in the Torah; therefore he was the 

patron of the Church, and of the orders of knights during the Middle Ages. 4. To call away from 

earth and bring men’s souls to judgment 10Mother Jones, http://www.motherjones.com/politics/2008/05/foreclosure-phil 11 ‘‘Obama vows crackdown on energy speculators: McCain fires back after Democrat tries to 

tie rival to ’Enron loophole’’ Associated Press 2008-06-22. http://www.msnbc.msn.com/id/ 

25318274/ 12 Jickling, Mark (2008-07-07). http://assets.opencrs.com/rpts/RS22912l20080707.pdf 13Davis, Trey (2005-01-07). http://www.universityofcalifornia.edu/news/2005/jan07.html 14 Rev 9:1 And the fifth angel sounded, and I saw a star fall from heaven unto the earth: and 

to him was given the key of the bottomless pit. Rev 9:11 And they had a king over them, which 

is the angel of the bottomless pit, whose name in the Hebrew tongue is Abaddon, but in the 

Greek tongue hath his name Apollyon. 15 Rev. 20:1-3 And I saw an angel come down from heaven, having the key of the bottomless 

pit and a great chain in his hand. And he laid hold on the dragon, that old serpent, which is 

the Devil, and Satan, and bound him a thousand years, and cast him into the bottomless pit, 

and shut him up, and set a seal upon him, that he should deceive the nations no more. 

the California Energy Resources Scheduling division of the California Department 

of Water Resources (CERS) as an ‘‘electric utility’’. The terms ‘‘electric consumer’’ 

and ‘‘electric utility’’ have the meanings given those terms in section 2602 of title 

16.8 Therefore, CARE’s efforts are the only direct ratepayer participation without 

the influence of their conflicting role as a market participant. 

MICHAEL9 AND THE BOTTOMLESS PIT

A ‘‘bottomless pit’’ of unsecured debt was opened up worldwide when the Congress 

allowed unregulated banks to be created in 2000 in the Enron loophole. The ‘‘Enron 

loophole’’ exempted most over-the-counter energy trades and trading on electronic 

energy commodity markets from government regulation. The ‘‘loophole’’ is so-called 

as it was drafted by Enron Corporation lobbyists working with U.S. Senator Phil 

Gramm (R-TX) to create a deregulated market for their experimental ‘‘Enron Online’’ initiative.10The ‘‘loophole’’ was enacted in sections § 2(h)(3) and (g) of the Commodity Exchange Act, 7 U.S.C. as a result of the Commodity Futures Modernization 

Act of 2000, signed by U.S. president Bill Clinton on December 21, 2000. It allowed 

for the creation, for U.S. exchanges, of a new kind of derivative security, the singlestock future, which had been prohibited since 1982 under the Shad-Johnson Accord, 

a jurisdictional pact between John S. R. Shad, then chairman of the U.S. Securities 

and Exchange Commission, and Phil Johnson, then chairman of the Commodity Futures Trading Commission. On June 22, 2008, then U.S. Senator Barack Obama 

proposed the repeal of the ‘‘Enron loophole’’ as a means to curb speculation on skyrocketing oil prices.11

The bottomless pit opened up when these unregulated banks selling over-thecounter (OTC) derivatives where created in the US by the government enacting the 

Enron loophole. The ‘‘Enron loophole’’ exempted most over-the-counter energy trades 

and trading on electronic energy commodity markets from government regulation.12

The ‘‘loophole’’ is so-called as it was drafted by Enron Corporation lobbyists working 

with U.S. Senator Phil Gramm (R-TX) to create a deregulated market for their experimental ‘‘Enron On-line’’ initiative.13 I’ve attached the check I got from Enron to 

show you we are battling the Devil. 

My theory is that this bank in Switzerland holding all the futures (derivatives) 

is the bottomless pit referred to in Revelations Chapter 914 and 2015 and that it is 

the modern day equivalent of the Oracle at Delphi that went away in 394 AD. It 

existed at the time of Jesus Christ was born. I got this link from my buddy who 
86 

is working for the UN bank in Switzerland. If we could take these boys out we could 

change the world. Will you help me to seal up the bottomless pit? 

I. Market developments in the first half of 2008 

The notional amounts outstanding of over-the-counter (OTC) derivatives 

continued to expand in the first half of 2008. Notional amounts of all types 

of OTC contracts stood at $683.7 trillion at the end of June, 15% higher 

than six months before (Table 1). Multilateral terminations of outstanding 

contracts resulted in the first ever decline of 1% in the volume of outstanding credit default swaps (CDS) since the first publication of CDS statistics in December 2004. The average growth rate for outstanding CDS 

contracts over the last three years has been 45%. In contrast to CDS markets, markets for interest rate derivatives and FX derivatives both recorded 

significant growth. Open positions in interest rate derivatives contracts rose 

by 17%, while those in FX contracts expanded by 12%. Gross market values, which measure the cost of replacing all existing contracts and are thus 

a better gauge of market risk than notional amounts, increased by 29% to 

$20.4 trillion at the end of June 2008. 

GOOD JOB

In order for Satan to be bound by Michael’s great chain all the futures (derivatives) must be unwound and all the underlying assets they are derived from must 

be revalued to eliminate this false debt so Satan that he should deceive the nations 

no more. 

I e-mailed you and faxed each member of Congress, the Senate, and the President 

in the middle of February 2009 about the presence of the bottomless pit which when 

I sounded the pit was at $683.7 trillion at the end of June 2008. See http:// 

www.bis.org/publ/otclhy0811.pdf?noframes=1 at page 5 

The Bottomless Pit has declined around 90 trillion dollars at the end of June 2009 

now it is at $592 trillion, see http://www.bis.org/publ/qtrpdf/rlqt0909.pdf at page 

45. This decline is attributed to a fear of further regulation of futures (derivatives). 

You have a duty to America and the world economies to seal the pit. 

Here is an explanation of what a credit default swap is (***note the Revelations 

chain is a Ponzi scheme). http://en.wikipedia.org/wiki/Creditldefaultlswap 

Essentially these unregulated banks own the world’s economies and there are no 

real assets backing any of this debt, so therefore; the bottomless pit. Everyone on 

the planet could work for the rest of their lives for the next 100 years and we still 

wouldn’t pay off this debt—clearly this is the bottomless pit referred to in Revelations. 

An unregulated futures market is nothing new however; for around one thousand 

eight hundred years it was called the Oracle at Delphi. Around 1400 BCE a goat 

herder noticed his sheep acted strange after peering into a particular chasm on 

Mount Parnassus. He looked in and found himself ‘‘agitated like one frantic’’. At 

least that is how the legend goes on the humble beginnings of the Oracle at Delphi. 

The effects of the brain altering vapors, Ruins were ultimately attributed to a divine source. Other people began inhaling the vapors so that they could prophesy. 

But the gas was so disorienting some fell into the cavern and were lost. So a tripod 

was built and an individual was appointed to sit over the chasm and prophesy. 

Originally, the perfect candidate was considered to be a young virgin girl. But after 

one of the virgins escaped with a young Thessalian it was decreed no prophetess 

(also called the Pythoness or the Pythia) would be appointed under 50 years of age. 

A booming industry grew up around the Oracle. Temples were built and rebuilt, 

priests were trained, rituals evolved and sacrifices were performed. Priests interpreted the incoherent utterances of the Pythia. Presents were brought to both placate the deity and in the hope of influencing a positive prophesy. The Delphic temple itself became one of the largest ‘‘banks’’ in the world. Delphi became a center 

for banking and commerce. 

The divine nature and associated deity changed a few times over the course of 

several centuries. When the profits of the Oracle began to decline it was declared 

that Poseidon was speaking through her. Later this changed to the goddess Themis 

and, finally, Apollo was determined to be presiding over Delphi. For over a millennia people traveled to the hill to consult the Oracle. Farmers consulted the Oracle on matters as simple as planting and harvest. Famous world leaders consulted 

on matters of conquest. Sophocles, Alexander the Great, and Croesus of Lydia all 

consulted the Oracle at one time or another. 

The priests’ interpretations may have been more coherent than the Pythoness but 

they generally remained cryptic and ambiguous. Croesus for example donated a for-
87 

tune to the oracle to find out if he should invade a neighboring country. He was 

told ‘‘If you go to war you will cause the destruction of a great empire’’. He went 

to war and not only was defeated but was captured. He sent word to the Oracle asking why he was misled. The word came back that he wasn’t misled, he had been 

told that there would be the destruction of a great empire and there was—his. The 

world famous Oracle of Delphi played an influential role in ancient history. For 

fourteen centuries it helped determine the course of empires. The prophesying was 

abolished in the 4th century as it conflicted with Christian beliefs that were at that 

time being embraced by Rome. 

Fast forward sixteen hundred and sixteen years to March 9, 2010 Commodity Futures Trading Commission Chairman Gary Gensler testimony: ‘‘Nearly 60 years 

after the futures markets were regulated, the first OTC swap was transacted in 

1981. During its early years, the OTC marketplace was highly tailored to meet specific risk management needs. Contracts were negotiated between dealers and their 

corporate customers seeking to hedge specific financial risks. In contrast to the regulated futures markets, these early OTC derivatives were not traded on exchanges. 

Instead, OTC derivatives were transacted bilaterally, with dealers standing between 

their various customers. In this market structure, dealers keep transactions on their 

books, leaving the financial institutions more interconnected with all of their customers and limiting the amount of relevant pricing information available to the public. 

In the last three decades, the over-the-counter derivatives marketplace has grown 

up, but it remains largely unregulated. Since the 1980s, the notional value of the 

market has ballooned from less than $1 trillion to approximately $300 trillion in the 

United States—that’s $20 in derivatives for every dollar of goods and services produced in the American economy. The contracts have become much more standardized, and rapid advances in technology—particularly in the last ten years—now can 

facilitate transparent trading of much of this market on electronic platforms. While 

so much of this marketplace has changed significantly, the constant that remains 

is that it is largely unregulated and still dealer dominated. 

It is now time to bring comprehensive regulation to this large and economically 

significant market. In well functioning markets, derivatives are meant to mitigate 

and help manage risk in the economy. Even if not for the 2008 financial crisis, this 

market should be regulated to achieve these goals. The financial crisis only highlights this in dramatically revealing how unregulated OTC derivatives and their 

dealers actually can heighten and concentrate risk to the great detriment of the 

American public. The need for broad based reform is the ultimate lesson of AIG and 

the broader risks brought about by the unregulated OTC derivatives market.’’ 

CONCLUSION

Please help me to seal the bottomless pit by giving CFTC authority to regulate 

energy futures (derivatives) and their clearing houses like ISOs and RTOs. Universal ratepayer suffrage is the key to workably competitive wholesale markets and 

providing open access to transmission services on a non-discriminatory basis. 

STATEMENT OF THE AMERICAN PUBLIC POWER ASSOCIATION (APPA) 

The American Public Power Association (APPA) appreciates the opportunity to 

provide the following statement for the record for the Senate Energy and Natural 

Resources Committee’s hearing on financial transmission rights (FTRs) and we 

would like to endorse the testimony given by Mr. Michael Henderson, representing 

the Arkansas rural electric cooperatives. 

APPA represents the interests of more than 2,000 publicly-owned electric utility 

systems across the country, serving approximately 45 million Americans. APPA 

member utilities include not-for-profit state public power agencies and municipal 

electric utilities that serve some of the nation’s largest cities. However, the vast majority of these publicly-owned electric utilities serve small and medium-sized communities in 49 states, all but Hawaii. In fact, 70 percent of our member systems 

serve communities with populations of 10,000 people or less. 

Overall, public power systems’ primary purpose is to provide reliable, efficient 

service to their local customers at the lowest possible cost, consistent with good environmental stewardship. Like hospitals, public schools, police and fire departments, 

and publicly-owned water and waste-water utilities, public power systems are locally created governmental institutions that address a basic community need: they 

operate on a not-for-profit basis to provide an essential public service, reliably and 

efficiently, at a reasonable price. 
88 

As the Senate continues its work in drafting legislation to regulate over-thecounter derivatives markets, we urge Congress to use caution to avoid creating duplicative authorities between the Commodity Futures Trading Commission (CFTC) 

and the Federal Energy Regulatory Commission (FERC) over the aspects of power 

supply and transmission markets that are run by Regional Transmission Organizations (RTOs) or Independent System Operators (ISOs). 

There are currently six RTOs/ISOs in several regions of the country under the jurisdiction of FERC. In these regions, market participants buy and sell a variety of 

electricity products and services in the centralized markets these RTOs/ISOs administer. These power supply-related products and services are typically not furnished 

by the RTO itself; instead they are sold by market participants through centralized, 

auction-type market structures that the RTO administers. For example, most RTOs/ 

ISOs operate ‘‘day-ahead’’ and ‘‘real-time’’ markets through which market participants buy and sell wholesale electric power. RTOs also administer markets for the 

purchase and sale of financial transmission rights (FTRs), which APPA members 

and other Load Serving Entities (LSEs) use to hedge the costs of transmission congestion associated with the transmission service they purchase from the RTOs/ISOs 

to move their power supplies to their retail customers (loads). 

While these FTRs are financial contracts, their terms, conditions and rates are 

comprehensively regulated by FERC and they should remain under FERC jurisdiction. These FTRs took the place of the physical transmission rights that LSEs had 

used to serve their loads prior to the implementation of RTO/ISO power supply markets. The ability of LSEs to have continued access to FTRs on reasonable terms and 

conditions is absolutely essential to their ability to serve their retail loads at reasonable rates and with less price volatility. 

RTO market rules are fully regulated by FERC and are set out in FERC-approved 

tariffs. The rates, terms and conditions applicable to any RTO product under a 

FERC tariff should not be subject to concurrent jurisdiction by CFTC. Concurrent 

jurisdiction could result in inconsistent regulations and uncertainty over enforceability of transactions. Because of this concern, if concurrent jurisdiction is found, 

CFTC should be required to consult with FERC regarding these markets and should 

be given statutory authority to cede jurisdiction to FERC. 

However, APPA is strongly concerned with market manipulation in electricity 

markets, and because of that we recognize that CFTC can play a beneficial role in 

policing and preventing such manipulation. CFTC and FERC could be most effective 

when working together to prevent manipulation in energy markets run by RTOs. 

APPA would therefore support concurrent FERC and CFTC jurisdiction only over 

market manipulation in RTO-administered markets. APPA would urge the two 

agencies to pool their resources and expertise to provide more comprehensive oversight in this specific area. 

In conclusion, while APPA fully supports legislation to curb manipulation in the 

OTC derivatives market, we urge Congress to use caution when drafting legislation 

in this area to ensure it does not have an unintended, adverse effect on retail electric and natural gas customers. From APPA’s perspective, a well drafted bill will 

include the provisions necessary to curb market manipulation while preserving 

FERC’s primary jurisdiction over RTO/ISO markets, including the FTR markets to 

hedge against energy price volatility. 

FPL GROUP, 

FEDERAL REGULATORY AFFAIRS, 

Washington, DC, March 26, 2010. 

Hon. JEFF BINGAMAN, 

Chairman, Committee on Energy and Natural Resources, U.S. Senate, 304 Dirksen 

Senate Office Building, Washington, DC. 

DEAR CHAIRMAN BINGAMAN: I am writing to supply additional information for the 

record of the hearing held by the Committee on ‘‘Financial Transmission Rights and 

Other Electricity Market Mechanisms’’ on March 9, 2010. Specifically, I am writing 

in response to questions raised by Commodity Futures Trading Commission Chairman Gary Gensler about the accuracy of an example I used in my testimony involving financial hedges of wholesale power sales into the New Jersey Basic Generation 

Service (NJ BGS) auction. 

The question is whether these financial hedges were standard products that 

would be forced to trade on exchanges under various legislative proposals, requiring 

the posting of significant collateral and creating liquidity risk exposure, or custom 

products that would not be forced to trade on exchanges. In my testimony, I as-
89 

1 CHAIRMAN B1NGAMAN: ‘‘Let me ask on this specific that Joseph Kelliher talked about 

there, the auction that occurred ... in New Jersey last month, What is your thinking about the 

role the CFTC would play on that kind of a—’’ 

MR. GENSLER: ‘‘I am glad you asked it. I understand the facts on that, probably none. I 

think it is a red herring, with all respect to Chairman Kelliher. I think it is probably a cash 

transaction that is excluded under the Commodity Exchange Act. We do not cover cash or physical spot or forward contracts. If Congress were to move forward and actually suggest that we 

cover broad, over-the-counter derivatives, it would only be the standard transactions that would 

be recommended to be brought to central clearing, and I think the transaction he was describing, if it were an over-the-counter derivative, would actually be customized or tailored,’’ 

Financial Transmission Rights and Other Electricity Market Mechanisms, Hearing Before the 

Senate Comm. On Energy and Nat. Resources, 111th Cong. 44-45 (March 9, 2010) (unofficial 

transcript). 

serted these financial hedges were standard products. Following is an excerpt from 

my written testimony: 

It is critical that these companies continue to have access to the OTC 

market for these hedges. Requiring suppliers to hedge on an exchange 

would expose them to significant liquidity risk for cash margining. The cost 

of this risk would ultimately be borne by the utilities’ customers via higher 

prices charged for the full requirements service. For example, in February 

utilities in New Jersey purchased approximately 2,500 MW for a three-year 

term. If this entire volume were hedged on an exchange, suppliers would 

have had to post about $1 billion in cash to cover initial margin and variation margin. This $1 billion would have been added to bids accepted for 

the auction and ultimately would have been borne by consumers in New 

Jersey. There are a number of other states that conduct similar auctions. 

They would face a similar cost premium to reflect the additional working 

capital costs that suppliers would have to bear if the OTC markets are not 

available for the hedging needed to provide these types of products. Competition would also decline as the liquidity risk would simply be unacceptable to many suppliers. It is a basic tenet of markets that fewer participants would result in higher prices to customers. 

At the hearing, Chairman Gensler suggested the NJ BGS example in my testimony was a ‘‘red herring’’, maintaining that the transactions involved were physical 

sales of wholesale power outside CFTC jurisdiction or financial hedges that were 

custom products rather than standard products.1 I write to provide additional information demonstrating these financial hedges are indeed standard products, and 

stand by the accuracy of my testimony. 

The example in my testimony described a typical full requirements product that 

many utilities procure to provide retail electric service. The NJ BGS auction is one 

of the most competitive and highly regarded wholesale power procurement auctions 

in the country. The product procured in the NJ BGS auction includes electricity delivered in quantities that match the utilities’ load, or a percentage thereof, in each 

hour of the day, ancillary services and other products, hence they are called full requirements products. The Federal Energy Regulatory Commission (FERC) has jurisdiction over these wholesale power sales. A supplier of the full requirements product 

to serve one block of firm load in the Public Service Electric and Gas (PSE&G) service territory would have the obligation to serve 1.18% of PSE&G’s firm load at any 

given hour for three years. The load obligation varies by season and time of day, 

but has a peak load of 99 megawatts and an average load of 45 megawatts. 

Given the uncertainty regarding future wholesale power prices, sellers often 

hedge their positions with standardized products. These standardized hedges consist 

of one of, or a combination of (i) physical wholesale power purchases subject to 

FERC regulation and (ii) financial products purchased from over-the-counter (OTC) 

markets. The supplier would also enter into financial swaps to hedge the price risk 

between the liquid trading point and the utility’s delivery point, commonly referred 

to as basis swap transactions. If the transaction is hedged with a combination of 

financial products, the physical delivery of power to meet the utility’s load obligations would be purchased in the physical spot market. 

In the example used in my testimony, a supplier of one block of PSE&G firm load 

would procure standard on and off peak block power products of seasonal, yearly 

or multi-year terms at PJM West, the closest liquid trading hub to the PSE&G delivery zone. The block power purchases would be made in such a fashion to as closely as possible replicate the expected load obligation by month. However, due to the 

nature of the standardized products that are traded at the PJM West Hub, quantities that exactly match PSE&G’s expected load are not typically available. The 

same process of buying on and off peak block volumes in seasonal, yearly or multi- 
90 

2 A customized product utilized to hedge a supplier’s firm load obligation to PSE&G would contain non-standard terms to the transaction such as a shaped hourly volume rather than fixed 

block volumes of energy, or would have other terms that would not be readily tradable in the 

market by multiple parties. It should be noted, however, that the supplier of such non-standard 

products would most likely have to hedge its exposure using a combination of standard products 

and then manage the exposure resulting from the variations between the non-standard product 

and the standard hedges. 

year terms would be followed for the basis swap transactions. The supplier of the 

full requirements product then manages the exposure resulting from variations between the actual load volume and the procured hedge products. 

None of the financial products used to hedge the risk associated with these forward wholesale power sales into the NJ BGS are custom products. These are standard OTC products with fixed volumes and terms associated with liquid pricing 

points2. NYMEX and ICE trade multiple products associated with the PJM West 

Hub, some of which could be used to hedge the price risk associated with buying 

the PJM West Hub block power referenced in the example above. The NYMEX and 

ICE purchases would likely be considered standardized under the pending legislation. Similarly, both the NYMEX and Nodal Exchange trade multiple basis swap 

products, including the basis swap between the PJM West Hub and the PSE&G 

service territory, and such products would likely be considered standardized products. Legislative proposals that would force trading and clearing of standard products would indeed mandate the trade of these products on exchanges. 

Requiring suppliers to hedge on an exchange would expose them to significant liquidity risk for cash margining. The cost of this risk would ultimately be borne by 

the utility’s customers via higher prices charged for the full requirements service. 

In this particular instance, financially hedging one block of PSE&G firm load with 

a standard 50 megawatt block of PJM West energy on an exchange versus OTC 

would have resulted in an initial cash margin posting of $6.6 million and a peak 

cash margin posting to the exchange of $21 million. Extrapolating this exposure to 

cover the entire auction volume would have required suppliers to post over $1 billion in cash to cover the exchange requirements. 

I continue to maintain that requiring energy companies and end users to conduct 

all of their transactions of standard products on exchanges and subjecting those 

transactions to costly central clearing requirements would result in significant price 

increases and reduced participation in the market, without any commensurate reduction in risk. This is why I support an end-user exemption for both wholesale and 

retail market participants 

Sincerely, 

JOSEPH T. KELLIHER, 

Executive Vice President. 

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