FINAL REPORT ON 

PRICE MANIPULATION IN WESTERN MARKETS 

FACT-FINDING INVESTIGATION OF 

POTENTIAL MANIPULATION OF 

ELECTRIC AND NATURAL GAS PRICES 

DOCKET NO. PA02-2-000 

Prepared by the Staff of the 

Federal Energy Regulatory Commission 

March 2003 

Table of Contents 

Docket No. PA02-2-000 Price Manipulation in Western Markets 

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Table of Contents

Title Page

Executive Summary ............................................................................................................ ES-1

I. Manipulations in the California Natural Gas Spot Markets Forced Upward 

Pressure on Wholesale Electric Prices .............................................................................. I-1 

Spot Market Natural Gas Prices at California Borders Were Extraordinarily High ............ I-2 

Supply/Demand Imbalance and Flawed Market Rules Drove Wholesale Electric Prices 

Higher During 2000 and 2001 .............................................................................................. I-9 

 Weather Extremes and High Demand ............................................................. I-10 

Flawed Market Rules and Regulatory Policies Magnified Adverse Conditions................... I-12 

Transportation Constraints and Spot Market Dysfunctions Contributed Significantly to 

Higher Spot Market Natural Gas Prices at the California Border......................................... I-13 

Market Manipulations Significantly Influenced Reported Spot Prices for Natural Gas 

in California ......................................................................................................................... I-17 

 Trading in Anomalous Patterns at Topock ...................................................... I-17 

 False Reporting of Market Transactions to Publications................................. I-18 

II. Analysis of Gas Trading Activity in Southern California .......................................... II-1 

Summary............................................................................................................................... II-1 

Background........................................................................................................................... II-2 

Descriptive Analysis ............................................................................................................. II-3 

Churn Trading and Netting Arrangement ............................................................................. II-7 

Econometric Analysis ........................................................................................................... II-8 

Linkages Between Physical and Financial Trading .............................................................. II-9 

Investigation of Reliant Trading ........................................................................................... II-9 

 Exploratory Descriptive Analysis.................................................................... II-11 

 Reliant’s SoCalGas Trading on EnronOnline Stands Out ............................... II-13 

 Reliant’s Purchases at Topock......................................................................... II-15 
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 Reliant-Enron Churn Trades Sometimes Dominated a Day’s Trading............ II-17 

 Reliant Trading and Market Volatility............................................................. II-20 

 Reliant Did Most of the Churning ................................................................... II-23 

Reliant’s Churning................................................................................................................ II-23 

 Reliant’s Churn Days....................................................................................... II-23 

 

 Reliant’s Churning Peaked in December 2000................................................ II-25 

 Reliant Bought and Sold in Bursts................................................................... II-26 

 Example of Effect of Burst Trading: December 11, 2000 ............................... II-27 

 Reliant’s Trading Had the Effect of Maximal Market Impact......................... II-30 

 Reliant’s Churning Raised the Index Prices .................................................... II-30 

 

 Churning on EOL Showed Price Gyrations to the Whole Market................... II-31 

Reliant’s Western Market Gas Trading Operations.............................................................. II-32 

 LADWP Contract ............................................................................................ II-34 

 Southern California Gas Balancing Rules ....................................................... II-34 

 Interview With Reliant’s Southern California Spot Gas Traders .................... II-37 

 Netting Arrangements for El Paso Cuts........................................................... II-39 

 Econometric Analysis of Reliant Trading Impact on Gas Prices..................... II-43 

Intraday EOL Price Analysis ................................................................................................ II-44 

Interday EOL Price Analysis and Counterfactual Gas Prices............................................... II-46 

Physical/Financial Linkages in Reliant’s Trading ................................................................ II-50 

How Gas Swaps Work.......................................................................................................... II-51 

Reliant’s Financial Trading Activity—Basis Trading and Swaps ........................................ II-52 

Reliant’s Southern California Basis Trades .......................................................................... II-53 

Reliant’s Southern California Swaps .................................................................................... II-53 

Conclusion Concerning Reliant Trading............................................................................... II-58 
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Recommendation: Remedial Action To Address Reliant’s Churning .................................. II-60 

III. Manipulations of Published Natural Gas Price Indices............................................ III-1

Developments in the Investigation Since August 13, 2002 .................................................. III-2 

Company-Specific Reporting Practices ................................................................................ III-4 

Dynegy.................................................................................................................................. III-5 

AEP....................................................................................................................................... III-8 

Williams................................................................................................................................ III-9 

CMS ...................................................................................................................................... III-11 

El Paso Merchant Energy ..................................................................................................... III-12 

Staff Reaction to the Admissions of False Reporting ........................................................... III-15 

Responses to the October 22, 2002 Data Request ................................................................ III-19 

Duke Energy Trading and Marketing ................................................................................... III-20 

Coral Energy ........................................................................................................................ III-22 

Mirant.................................................................................................................................... III-23 

BP Energy Company............................................................................................................. III-24 

Reliant................................................................................................................................... III-24 

Sempra .................................................................................................................................. III-26 

Aquila Merchant Services .................................................................................................... III-27 

Staff Reaction to the October 22, 2002 Data Request .......................................................... III-29 

Staff Attempts To Verify the Accuracy of the Reported Indices.......................................... III-30 

Industrywide Reporting Issues.............................................................................................. III-31 

The Testimony of Michele Markey ...................................................................................... III-32 

The Effect of Enron and EOL on the Published Price Indices.............................................. III-33 

Reform of the Price Reporting Process................................................................................. III-38 

Company Changes ................................................................................................... III-38 
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Proposal of the Committee of Chief Risk Officers .................................................. III-39 

Changes by the Trade Press in the Price Index Methodologies............................... III-43 

Platts...................................................................................................................................... III-43 

NGI ....................................................................................................................................... III-46 

IntercontinentalExchange .................................................................................................... III-47 

Staff Reaction to the Proposed Changes .............................................................................. III-48 

Future Index Reporting......................................................................................................... III-49 

Staff Recommendations to the Commission......................................................................... III-51 

Conclusion ............................................................................................................................ III-54 

IV. Staff Alternative Mitigation Proposal......................................................................... IV-1

Summary and Conclusions ................................................................................................... IV-1

Introduction........................................................................................................................... IV-1 

Why California Gas Spot Prices Should Not Be Used for Price Mitigation......................... IV-4 

Gas Prices Were Driven by Power Prices Once Pipeline Capacity Became Constrained .... IV-5 

Pipeline Capacity Constraints Were Not Entirely Market Related....................................... IV-6 

California Gas Prices Were Artificially High ....................................................................... IV-7 

Spot Gas Prices Contained a Transportation Premium Far in Excess of Pipeline 

Transportation Rates ............................................................................................................. IV-7 

Under the Market-Clearing Price Mechanism, Generator Operating Profit 

Increases With the Gas Price ................................................................................................ IV-9 

Modification of the Mitigated Market-Clearing Price Methodology Is Needed................... IV-11 

Options for Establishing Natural Gas Prices for Power Price Mitigation............................. IV-11 

How the Alternate Market-Clearing Price Mechanism Would Work................................... IV-13 

Impact of the Proposed Alternate Mitigation Methodology ................................................. IV-15 

Use of Incremental Versus Average Heat Rates................................................................... IV-16 

Response to Comments on Initial Report ............................................................................. IV-17 
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V. The Influence of Electricity Spot Prices on Electricity Forward Prices ................... V-1

Summary of Results.............................................................................................................. V-1 

Background ...................................................................................................................... ... V-1 

Comparison of the Two Studies......................................................................................... ... V-3 

Staff’s Analysis..................................................................................................................... V-4 

Basic Economic and Statistical Methodology ...................................................................... V-4 

 Economics........................................................................................................ V-4 

 Statistical Methodology ................................................................................... V-5 

Data....................................................................................................................................... V-6 

 Sample Size ..................................................................................................... V-6 

 Hubs and Duration Classes.............................................................................. V-7 

 Forward Gas and Electricity Spot Price Data .................................................. V-8 

 Audit Process and Results ............................................................................... V-9 

Regression Specification....................................................................................................... V-9 

 Definition of Sample Period ............................................................................ V-9 

 Basic Equation................................................................................................. V-10 

 Aggregation ..................................................................................................... V-10 

 Instrumental Variables..................................................................................... V-11 

Regression Results................................................................................................................ V-12 

 “During” Period Results Summary.................................................................. V-12 

 “After” Period Results Summary..................................................................... V-14 

Interpreting Regression Results ............................................................................................ V-16 

Conclusion ............................................................................................................................ V-18 

Recommendation .................................................................................................................. V-19 
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VI. Trading Strategies, Economic Withholding, Inflated Bidding, and Other 

Anomalous Activities .......................................................................................................... VI-1 

Initial Recommendations ...................................................................................................... VI-1 

Background ......................................................................................................................... VI-2 

Overview of the Cal PX and Cal ISO Operations................................................................. VI-4 

The Cal ISO’s and Cal PX’s MMIP Contains an Antigaming Provision and an 

Anomalous Market Behavior Provision................................................................................ VI-6 

Staff Finds That There May Have Been Numerous Instances of the Misconduct 

Addressed in the MMIP ....................................................................................................... VI-10 

The Enron Trading Strategies and Their Impact on Prices ................................................... VI-11 

 Price Manipulation—Load Shift...................................................................... VI-12 

 Price Maximization—Exports ......................................................................... VI-15 

 Trading Strategies Based on False Information............................................... VI-19 

Transmission Congestion Strategies ..................................................................................... VI-26 

Ancillary Services Strategies ................................................................................................ VI-31 

 Recommended Commission Responses .......................................................... VI-35 

Enron’s Business Model ....................................................................................................... VI-37 

Enron’s Business Partners..................................................................................................... VI-39 

Gaining Control of Assets..................................................................................................... VI-40 

 Recommended Commission Responses .......................................................... VI-42 

Filing Requirements.............................................................................................................. VI-44 

Economic Withholding of Generation and Inflated Bidding During May to 

October 2000......................................................................................................................... VI-45 

 The California Parties’ Analysis of Bidding Practices by In-State 

 Generators and Certain Importers.................................................................... VI-48 

Responses Filed by the In-State Generators and Importers .................................................. VI-51 

 Recommended Commission Responses .......................................................... VI-52 

Physical Withholding of Generation..................................................................................... VI-54 
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Reliant and BP Energy Traders Appear To Have Engaged in Coordinated Efforts To 

Manipulate Market Prices ..................................................................................................... VI-55 

Spot Prices in the Pacific Northwest—Docket No. EL01-10-000, et al. .............................. VI-56 

 Recommended Commission Responses .......................................................... VI-59 

VII. Wash Trading on EnronOnline ................................................................................. VII-1

Wash Trading on EnronOnline ............................................................................................. VII-1 

Choice Markets ..................................................................................................................... VII-2 

Wash Trades Within Choice Markets ................................................................................... VII-4 

Affiliate Price Manipulation ................................................................................................. VII-12 

One-to-Many Versus Many-to-Many Trading Platforms ..................................................... VII-13 

Summary and Conclusions Regarding Wash Trades on EnronOnline ................................. VII-14 

Recommendations................................................................................................................. VII-15 

VIII. The Profitability of EnronOnline Information Advantage.................................... VIII-1

Measuring Trading Profits .................................................................................................... VIII-2 

EOL Market-Making Profits................................................................................................. VIII-5 

Conclusions........................................................................................................................... VIII-7 

Recommendation .................................................................................................................. VIII-8 

IX. Enron’s Manipulation of the Natural Gas Markets, Portions of the Enron 

Black Box Revealed, and Forward Looking Recommendations .................................... IX-1 

Background ......................................................................................................................... IX-1 

The Relationship Between Natural Gas Financial Derivatives and the Underlying 

Physical Gas Contracts ......................................................................................................... IX-2 

 General Purpose for Physical and Financial Natural Gas Markets.................. IX-2 

 Importance of Liquidity in the Natural Gas Markets....................................... IX-3 

 Physical Transaction Values Dictate the Pricing of Financial Derivatives ..... IX-4 

 Relative Differences in Liquidity Across Markets Combined With Correlated 

 Values Between Those Markets Provides an Opportunity for Profitable 

 Manipulation.................................................................................................... IX-6 
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The General Strategy of Manipulating the Financial Markets Through Trading in the 

Physical Markets................................................................................................................... IX-9 

 Overview of Manipulation Strategies .............................................................. IX-9 

 Strategy To Profit From Upward Movement in Natural Gas Prices................ IX-9 

 Additional Profit Potentially Yielded From Cornering the Market ................. IX-10 

 Strategy To Profit From Downward Movement in Natural Gas Prices........... IX-10 

 An Alternative Variation in Which the Trader Gains Profits From the 

 Downward Movement in Prices ...................................................................... IX-11 

The Central Desk Manipulation............................................................................................ IX-12

 Unusual Circumstances Surrounding the Trading Activity ............................. IX-12 

 The June 14, 2001 Market Test ....................................................................... IX-14 

 The July 19, 2001 Manipulation...................................................................... IX-17 

Description of EnronOnline and Its Main Features .............................................................. IX-24 

The EOL Trading Platform................................................................................................... IX-25 

 The Lack of Transparency on the EOL Platform............................................. IX-26 

 Limit Orders on EOL....................................................................................... IX-27 

The Role of EOL in Enron’s Strategy and Market Power .................................................... IX-29 

The Role of EOL in Facilitating Market Manipulation ........................................................ IX-30 

ICE and TradeSpark: An Alternative Type of Electronic Platform...................................... IX-32 

 The Basic Structure of the Electronic Markets................................................ IX-32 

 Credit Risk and the Organization of ICE and TradeSpark .............................. IX-34 

 Contrasting ICE and TradeSpark With EOL ................................................... IX-37 

The Role of Voice Brokers ................................................................................................... IX-38 

Conclusion: Forward Looking Recommendations................................................................ IX-39 
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X. Analysis of Allegation That Williams Energy Marketing & Trading Company 

Attempted To Corner the Market in California for January 2001 Gas ........................ X-1

Williams Energy Marketing & Trading Company................................................................ X-1 

The Allegation That Williams Tried To Corner the Market and Drive Up Prices in 

California .............................................................................................................................. X-2 

The Commission Staff’s Investigation of the Allegation...................................................... X-3 

Conclusion of the Commission Staff’s Investigation............................................................ X-3 

Appendices 

Appendix II-A: Supporting Tables for Analysis of Reliant Natural Gas Transactions....... II-A-1 

Appendix II-B: Econometric Analysis of Impact of Reliant Trading on Gas Prices .......... II-B-1 

Appendix V-A: Details of Data Validation ......................................................................... V-A-1 

Appendix V-B: Comparison of Forward Gas Curves.......................................................... V-B-1 

Appendix V-C: Disaggregated Regressions ........................................................................ V-C-1 

Appendix V-D: Serial Correlation....................................................................................... V-D-1 

Appendix IX-A: A Detailed Description of Trader 1’s Trading Positions and Profits for 

the June 14, 2001 Market Test.............................................................................................. IX-A-1 

 
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Docket No. PA02-2-000 Price Manipulation in Western Markets 

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 List of Figures 

Figure Title Page

I-1 Spot Natural Gas Prices at SoCal for the Periods July 1999 – 

 March 2000 and July 2000 – March 2001........................................................... I-5 

I-2 Monthly Average Spot Gas Prices at Henry Hub and SoCal .............................. I-7 

I-3 Daily Spot Natural Gas Prices at Selected Basins and SoCal, 

 July 1999 – March 2000 ...................................................................................... I-7 

I-4 Daily Gas Prices at Selected Basins and SoCal, 

 July 2000 – March 2001 ...................................................................................... I-8 

I-5 Daily Natural Spot Gas Prices at Main Canadian Production Point 

 (NOVA(AECO-C)) and PG&E, July 1999 – March 2000 .................................. I-8 

I-6 Daily Spot Natural Gas Prices at Main Canadian Production Point 

 (NOVA(AECO-C)) and PG&E, July 2000 – March 2001 .................................. I-9 

II-1 Day-Ahead Trades at SoCal, January 31, 2001 for February 1, 2001 Gas.......... II-5 

II-2 EOL Average Price vs. Gas Daily Midpoint Price at SoCal, 

 November 2000 – June 2001 .............................................................................. II-6 

II-3 SoCalGas Transmission Facilities ...................................................................... II-12 

II-4 Day-Ahead Trades at SoCal, January 31, 2001 for February 1, 2001 Gas.......... II-18 

II-5 Day-Ahead Trades at SoCal, February 2, 2001 for February 5, 2001 Gas.......... II-19 

II-6 Day-Ahead Trades at SoCal, June 11, 2001 for June 12, 2001 Gas.................... II-20 

II-7 Day-Ahead Trades at SoCal, November 28, 2000 for 

 November 29, 2000 Gas ...................................................................................... II-21 

II-8 Day-Ahead Trades at SoCal, January 29, 2001 for January 30, 2001 Gas.......... II-21 

II-9 Day-Ahead Trades at SoCal, June 7, 2001 for June 8, 2001 Gas........................ II-22 

II-10 December Price Chart.......................................................................................... II-25 

II-11 Day-Ahead Trades at SoCal, December 11, 2000 for 

 December 12, 2000 Gas....................................................................................... II-28 

II-12 Reliant’s Daily Swap Net Position and Gas Daily SoCal Large Packages 

 Midpoint Price Index, November 2000 – February 2001.................................... II-54 
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II-13 Financial Trader A’s Daily Net Volume Traded for Rest-of-December Gas, 

 Compared With Gas Daily SoCal Large Packages Midpoint Price Index, 

 November 27, 2000 – December 29, 2000.......................................................... II-56 

II-14 Financial Trader A’s Daily Net Volume Traded for Rest-of-February Gas, 

 Compared With Gas Daily SoCal Large Packages Midpoint Price Index, 

 February 6, 2001 – February 24, 2001 ................................................................ II-57 

III-1 SoCal Topock: EnronOnline and Gas Daily Index Value................................... III-35 

IV-1 Palo Verde Power Price vs. California Gas Price, 

 High Power Prices Preceded Gas Price Rise....................................................... IV-5 

IV-2 Disparity Between Southern California and Southwest Spot Prices Far 

 Exceeds Transportation Rates............................................................................. IV-8 

IV-3 Disparity Between Northern California and Canadian Spot Prices Far 

 Exceeds Transportation Rates............................................................................. IV-9 

IV-4 Generator Profitability Rises With Gas Cost ..................................................... IV-10 

IV-5 Using Producing Area Prices for the Market Clearing Price Provides 

 Reasonable Operating Profit ............................................................................... IV-14 

IV-6 Operating Profit Comparison, Southern California vs. Southwest Index ........... IV-15 

IV-7 Monthly Operating Profit Using Incremental Heat Rates................................... IV-16 

IX-1 The Relevant Hours: Comparison of Spot and Short-Term Henry Hub 

 Based Physical and Financial Product Prices on June 14, 2001 ......................... IX-15 

IX-2 Comparison of Spot and Short-Term Henry Hub Based Physical and 

 Financial Product Prices on June 14, 2001 ......................................................... IX-16 

IX-3 July 19, 2001 Morning Hours: EOL Henry Hub Next-Day 

 Physical Market Maker Activity and EOL-Based Transaction Prices for 

 Related Financial Products.................................................................................. IX-19 

IX-4 Net August OTC Swap Positions and July Gas Daily Financial 

 Position Changes for Trades on July 19, 2001.................................................... IX-21 

IX-5 OTC Swap Trading ............................................................................................. IX-22 
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Docket No. PA02-2-000 Price Manipulation in Western Markets 

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 List of Tables 

Table Title Page

I-1 Various Delivered Natural Gas Prices................................................................. I-6 

I-2 Interstate Pipeline Design Capacity to California ............................................... I-13 

I-3 Capacity Releases Above the Maximum Tariff Rate .......................................... I-15 

II-1 Top 15 Counterparties by Gross Volume and Top Locations by Gross 

 Volume (EOL, November 1, 2000 – June 30, 2001)........................................... II-14 

II-2 EOL Trading Activity in Topock Spot Gas, Days on Which Enron 

 or Reliant Purchased More Than 270,000 MMBtu/d, 

 November 2000 – June 2001............................................................................... II-16 

II-3 Reliant Churn Days at SoCal (Topock and Ehrenberg), Summary of 

 Physical Daily Trades of Reliant and All Other Counterparties.......................... II-24 

II-4 EOL Trading in Topock Spot Gas, December 11, 2000...................................... II-29 

II-5 Netting Example—Settlement Without Netting.................................................. II-40 

II-6 Netting Example—Settlement With Netting....................................................... II-41 

II-7 Reliant’s Profit From EOL-Reliant Netting Agreement, 

 November 2000 – June 2001............................................................................... II-42 

II-8 EOL-Reliant Netting Agreement’s Impact on Physical Spot Trading 

 Outcomes, November 2000 – June 2001............................................................. II-43 

II-9 Counterfactual Price Summary............................................................................ II-50 

II-10 A Swing Swap Trade With Reliant as Buyer ...................................................... II-51 

II-11 Profitability of Swing Swap ................................................................................ II-52 

III-1 Price Reporting Summary, July 2000 – December 2001..................................... III-14 

III-2 December Southern California Average of (Spot Price – Published Index) ....... III-17 

V-1 Sample Size by Region and Period Definition .................................................... V-7 

V-2 Spot Power Coefficient by Time-to-Delivery Class: “During” Period................ V-13 
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V-3 Spot Power Coefficient by Time to Delivery and Hub: 

 “During” Period................................................................................................... V-14 

V-4 Spot Power Coefficient by Contract Duration Class: “After” Period.................. V-14 

V-5 Spot Power Coefficient by Hub and Duration: “After” Period ........................... V-15 

V-6 Impact of Estimated Spot Power Elasticity on Forward Price of Power 

 (January 1, 2001 – March 31, 2001).................................................................... V-17 

VI-1 Implied Heat Rate ............................................................................................... VI-47 

VI-2 Implied Heat Rate ............................................................................................... VI-58 

VI-3 Estimated Capital Cost Recovery ....................................................................... VI-58 

VII-1 Trades Completed During Choice Markets, by Month....................................... VII-3 

VII-2 Trades Executed During Choice Markets, by Trader.......................................... VII-4 

VII-3 Wash Trades Completed During Choice Markets, by Month............................. VII-6 

VII-4 Wash Trades Completed During Choice Markets, by Trader............................. VII-7 

VII-5 Wash Trades Completed During Choice Markets, by Counterparty .................. VII-8 

VII-6 Wash Trades Completed During Choice Markets, by Delivery Location .......... VII-9 

VII-7 Days in Which Individual Counterparties Conducted the Most Wash Trades 

 During Choice Markets....................................................................................... VII-10 

VII-8 Example of a Wash Trade Sequence for Trades Between EOL and 

 Entergy-Koch Trading, LP.................................................................................. VII-11 

VII-9 Affiliate Trading Between EOL and Enron Affiliate EPMI Long Term 

 Southwest............................................................................................................ VII-13 

VIII-1 Profits to Enron From EOL Market Making in Five Key Products.................... VIII-9 

VIII-2 Profits to Enron From EOL Market Making: Trades for Physical 

 Delivery of Power at the California-Oregon Border........................................... VIII-10 

VIII-3 Profits to Enron From EOL Market Making: Trades for Physical 

 Delivery of Power at Palo Verde, Arizona.......................................................... VIII-11 

VIII-4 Profits to Enron From EOL Market Making: Trades for Physical 

 Delivery of Gas at Topock, California................................................................ VIII-12 
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VIII-5 Profits to Enron From EOL Market Making: Trades for Physical 

 Delivery of Gas at Henry Hub, Louisiana........................................................... VIII-13 

VIII-6 Profits to Enron From EOL Market Making: Trades in NYMEX 

 Look-Alike Swaps .............................................................................................. VIII-14 
Executive Summary 

Docket No. PA02-2-000 Price Manipulation in Western Markets ES-1

Executive Summary 

Overview 

This Report is the culmination of a yearlong effort by Commission 

Staff to determine whether and, if so, the extent to which California 

and Western energy markets were manipulated during 2000 and 2001. 

While Staff found significant market manipulation, this evidence does 

not alter the Commission’s original conclusion, set forth in its 

December 15, 2000 Order, that significant supply shortfalls and a 

fatally flawed market design were the root causes of the California 

market meltdown. 

The underlying supply-demand imbalance and flawed market design 

greatly facilitated the ability of certain market participants to engage in 

manipulation. In addition, the ability to pass through gas prices in 

electric power prices provided no check on gas buyers’ willingness to 

pay. 

For the first 2 years of its operation, the California market performed 

well and saved the state’s customers billions of dollars. Only after the 

Pacific Northwest could no longer provide abundant supplies of lowcost hydropower to the regional market did the negative effects of too 

little infrastructure and poorly designed market rules adversely affect 

customers’ bills. 

A key conclusion of this Report is that markets for natural gas and 

electricity in California are inextricably linked, and that dysfunctions 

in each fed off one another during the crisis. Spot gas prices rose to 

extraordinary levels, facilitating the unprecedented price increase in 

the electricity market. Dysfunctions in the natural gas market appear to 

stem, at least in part, from efforts to manipulate price indices compiled 

by trade publications. Reporting of false data and wash trading are 

examples of efforts to manipulate published price indices. This Report 

makes recommendations for conditions the Commission should 

impose to ensure that price indices represent better barometers of 

actual prices. 

In a related finding, Staff concludes that large-volume, rapid-fire 

trading by a single company, in what was incorrectly assumed to be a 

liquid market, substantially increased natural gas prices in California. 

To compensate for this, Staff reiterates the recommendation of its 

August 2002 Initial Report, which called for the Commission to alter 

the natural gas pricing methodology employed in the California 
Executive Summary 

Docket No. PA02-2-000 Price Manipulation in Western Markets ES-2

Refund Proceeding. Using Staff’s recommended producing area plus 

transportation price, instead of published price indices, while 

accounting for scarcity and keeping electricity providers whole for the 

actual prices they paid for natural gas, would result in larger refunds to 

California. 

This Report finds that many trading strategies employed by Enron and 

other companies were undertaken in violation of antigaming 

provisions of the Commission-approved tariffs for the Cal ISO and Cal 

PX. Staff recommends the Commission initiate proceedings to require 

guilty companies to disgorge profits associated with these tariff 

violations. This disgorgement would affect activities beginning 

January 1, 2000 through June 21, 2001, and not just those during the 

October 2, 2000 through June 21, 2001 refund period. These 

disgorgements would be in addition to the refunds resulting from the 

California Refund Proceeding. 

A central mandate in undertaking this Staff fact-finding investigation 

was to determine whether the dysfunctional spot market for electricity 

had an impact on the forward prices reflected in long-term power 

supply agreements. The Staff’s analysis finds that spot prices 

influenced forward prices negotiated during the January 1, 2000 

through June 21, 2001 crisis period. The influence is greatest for 

contracts with 1- to 2-year terms. 

Staff concludes that EnronOnline (EOL), which gave Enron 

proprietary knowledge of market conditions not available to other 

market participants, was a key enabler of wash trading. This created a 

false sense of market liquidity, which can cause artificial volatility and 

distort prices. Enron’s informational trading advantage on EOL was 

lucrative; the company took large positions and was an active, 

successful speculator. Staff estimates Enron’s speculative profits from 

EOL exceeded $500 million in 2000 and 2001. These speculative 

profits in financial instruments allowed Enron to sustain trading losses 

in physical trading. Staff further finds that Enron manipulated thinly 

traded physical markets to profit in financial markets. The Report 

recommends that the Commission prohibit the use of one-to-many 

trading platforms such as EOL and explicitly prohibit wash trading. 

Staff concludes that prices in the California spot markets were affected 

by economic withholding and inflated bidding. Staff finds this violated 

the antigaming provisions of the Cal ISO and Cal PX tariffs and 

recommends proceedings to require disgorgement of profits associated 

with these inflated prices. This investigation did not address physical 

withholding of generation, an issue the Commission is addressing 

separately. 
Executive Summary 

Docket No. PA02-2-000 Price Manipulation in Western Markets ES-3

The balance of this executive summary discusses in greater detail the 

findings and recommendations in the body of this Report. 

Background 

On February 13, 2002, in Docket No. PA02-2-000, the Commission 

directed Staff to investigate whether any entity, including but not 

limited to Enron or any of its affiliates, manipulated short-term prices 

for electric energy or natural gas in the West or otherwise exercised 

undue influence over these prices and whether this resulted in unjust 

and unreasonable rates in long-term power sales contracts. 

In August 2002, Staff released its Initial Report in Docket No. PA02-

2-000.1 In that Report, Staff recommended the initiation of various 

company-specific proceedings2

 to further investigate possible 

misconduct and recommended several generic changes to marketbased tariffs to prohibit the deliberate submission of false information 

or the deliberate omission of material information, and to provide for 

the imposition of both refunds and penalties for violations. Staff also 

concluded that the most widely used published price indices were 

compiled without adequate standards or controls, were subject to 

attempted manipulation, could not be independently verified, and 

should not be used for setting the market-clearing prices in the 

California Refund Proceeding. Accordingly, Staff recommended the 

use of producing-area natural gas prices plus transportation. Finally, 

Staff analyzed the now infamous Enron trading strategies and found 

many of them to be forms of gaming based on price manipulation and 

the falsification of information. 

Overall Organization and 

Primary Objectives of the 

Final Report 

This Final Report achieves a multitude of objectives, many of which 

were listed in the Initial Report. It begins with two core objectives: to 

provide the Commission with our analysis of whether spot power 

prices in the West were just and reasonable in 2000–2001 and whether 

spot power prices adversely affected long-term power prices. While 

the Commission has already held that spot electric prices were unjust 

 

1

The Initial Report is available on the Commission’s Web site at 

www.ferc.gov/electric/bulkpower/pa02-2/Initial-Report-PA02-2-000.pdf. 

2

These proceedings, which are currently pending before the Commission, are Docket 

Nos. EL03-113-000, EL03-114-000, and EL03-115-000. 
Executive Summary 

Docket No. PA02-2-000 Price Manipulation in Western Markets ES-4

and unreasonable, its refund methodology hinges on the use of a 

competitive gas input cost. Therefore, the first four chapters of this 

Report are dedicated to this critical gas issue and the fifth chapter 

addresses the correlation of spot electric prices to long-term electric 

prices. The remaining chapters address the other critical issues that 

help to explain the gas and electric markets in 2000 and 2001. 

This Report reflects the views of Staff only. It has not been considered 

or adopted by the full Commission. In addition, whenever this Report 

concludes that prices were or appear to have been manipulated, it does 

so in the context of determining whether rates were unjust and 

unreasonable under the Federal Power Act or the Natural Gas Act or 

whether persons may have violated tariffs or regulations under those 

acts. Those acts do not require that intent be proven in order to make a 

determination that rates are or were unjust and unreasonable or that a 

person violated tariffs or regulations under those acts. 

Chapter I: Context of the Gas 

and Electric Markets in the 

West 

In this chapter, Staff provides essential background and context of the 

gas and electric markets in the West during 2000–2001. We analyze 

many factors that affected prices, including reduced hydro output, 

supply/demand imbalance, flawed market rules, illiquidity at a key gas 

trading point, stringent pipeline balancing rules, low gas storage levels, 

and pipeline constraints. We conclude that the electric and gas markets 

were so inextricably interrelated that their dysfunctions fed off each 

other. 

Spot Gas Prices Reached Extraordinary Levels and Were Used to Set 

Clearing Prices for the Entire Electric Spot Market 

The crucial conclusions of this chapter are that spot gas prices 

reflected extraordinary basis differentials that far exceeded the cost of 

transportation and that the effects of these inflated gas prices were 

greatly magnified because they were used to compute clearing prices 

paid by most California wholesale buyers for spot power. In Chapters 

II to IV we examine the causes in more detail. 
Executive Summary 

Docket No. PA02-2-000 Price Manipulation in Western Markets ES-5

Chapter II: Topock Was 

Illiquid—A Single Company 

Substantially Increased 

Prices 

In this chapter, we conclude that Reliant engaged in a high-volume, 

rapid-fire trading strategy to purchase its physical spot gas needs at 

Topock. Reliant often bought and sold many times its needs in quick 

bursts, which significantly increased the price of gas in that market. 

We describe this as “churning” and define its characteristics later in 

the chapter. We use this term even though it has other connotations in 

securities or futures trading because it gives the best visual image of 

Reliant’s behavior. Reliant’s churning enabled it to reduce the overall 

cost of the gas it actually needed. Through its churning, Reliant 

profited by selling gas at or near the top of the price climb it caused. 

Reliant was often such a large presence at Topock (e.g., for the 3-

month period from December 2000 to February 2001, nearly 50 

percent of the spot gas trades at Topock on EOL were with Reliant) 

that its trading strategy moved the entire market price. Our analysis 

shows that the price of gas would have been lower by about 

$8.54/MMBtu in December 2000 and by about $1.69/MMBtu over the 

9 months of the California Refund Proceeding absent Reliant’s 

churning. These inflated gas prices significantly influenced index 

prices and the clearing prices paid by most California wholesale 

buyers for spot power. 

Staff concludes that these gas prices are not the result of competitive 

conditions and would not produce just and reasonable electric prices in 

the California Refund Proceeding. In Chapter IV of this Report, we 

recommend alternative gas prices for the Commission’s consideration 

in the California Refund Proceeding. 

Recommendations To Amend Gas Marketing Certificates and Generic 

Proceeding 

Reliant’s churning did not violate the blanket certificate under which it 

sold gas because Section 284.402 of the regulations contains no 

explicit guidelines or prohibitions. We recommend that Sections 

284.284 and 284.402 of the regulations be amended to provide explicit 

guidelines or prohibitions for trading natural gas under Commission 

blanket certificates. We also suggest a generic proceeding to develop 

appropriate reporting and monitoring requirements for sellers of gas 

under Commission certificates. 
Executive Summary 

Docket No. PA02-2-000 Price Manipulation in Western Markets ES-6

Chapter III: Traders 

Attempted To Manipulate 

Price Indices Through False 

Reporting 

Market participants provided false reports of natural gas prices and 

trade volumes to industry publications. These publications used the 

reports to compile price indices, and false reporting became epidemic. 

Five major traders (Williams, Dynegy, AEP, CMS, and El Paso 

Merchant Energy) have admitted that their employees falsified 

information provided to Gas Daily and Inside FERC, the most 

influential and relied-upon compilers of natural gas price indices. The 

false reporting included fabricating trades, inflating the volume of 

trades, omitting trades, and adjusting the price of trades. 

The predominant motives for reporting false information were to 

influence reported gas prices, to enhance the value of financial 

positions or purchase obligations, and to increase reported volumes to 

attract participants by creating the impression of more liquid markets. 

Market participants that sold power in California, or that were 

affiliated with such sellers, also had incentives to manipulate reported 

prices because the clearing price set for power was based, in part, on 

natural gas spot prices. 

Many traders acknowledged that false reporting was done openly in 

the industry. Some traders believed that the periodicals that prepared 

the indices were able to distinguish between fictional and accurate 

reports, but the Staff was unable to confirm that the periodicals could 

discern fictional trades and eliminate them from the index calculation. 

The widespread false reporting led Staff to conclude that reported 

prices did not reliably reflect market activity and, accordingly, that 

reported prices should not provide the basis for setting spot power 

clearing prices in the California Refund Proceeding. 

Recommendations for Changes in the Reporting Process 

Staff recommends various changes to the price reporting process. 

These changes will eliminate the ability and incentive of those 

reporting the data to manipulate the indices and will improve the price 

calculation methods. 

♦ Only data that can be audited and verified by the Commission or 

other agencies can be used to construct the natural gas or electric 

price index. 
Executive Summary 

Docket No. PA02-2-000 Price Manipulation in Western Markets ES-7

♦ Data sent to firms publishing natural gas or electric price indices 

must be provided by the risk management office of the company, 

not the trading desk or a trader, and must be certified by the chief 

risk officer. 

♦ The Commission should consider conditioning all electric marketbased rate authorizations and blanket gas marketing certificate 

authorities on the companies providing complete, accurate, and 

honest information to any entity that publishes the price indices. 

♦ The Commission should consider conditioning all electric and 

natural gas market-based rate authorizations on retaining all 

relevant data and information needed to reconstruct a published 

price index for a period of 3 years. 

♦ Any published natural gas or electric price indices for 

Commission-jurisdictional transactions (e.g., pipeline tariff rates, 

market-based electric sales) must be subject to audit to ensure the 

accuracy of the data going in and the calculations themselves. 

♦ The Commission should consider encouraging standard product 

definitions for published natural gas and electricity price indices 

and standard methodologies for calculating the price indices. 

Certain Companies Must Demonstrate That They Currently Have Sound 

Procedures in Place 

Staff recognizes the importance of accurate price indices in the overall 

health of competitive energy markets. The companies discussed at 

length in this chapter are significant participants in the U.S. electricity 

and natural gas markets. In order for the published price indices to be 

accurate and credible, firms publishing such indices must receive 

complete and accurate information from these companies. As such, 

Staff recommends that the following companies be required to 

demonstrate that they have corrected their internal processes for 

reporting trading data to the Trade Press or that they no longer sell 

natural gas at wholesale: 

♦ Dynegy 

♦ Aquila 

♦ AEP 

♦ El Paso Merchant Energy 

♦ Williams 

♦ Reliant 

♦ Duke 

♦ Mirant 
Executive Summary 

Docket No. PA02-2-000 Price Manipulation in Western Markets ES-8

♦ Coral 

♦ CMS 

♦ Sempra Energy Trading 

At a minimum, these companies need to show the following: 

♦ Those employees, including trading desk heads and managers, who 

participated in manipulations or attempted manipulations of the 

published price indices have been disciplined. 

♦ The company has a clear code of conduct in place for reporting 

price information. 

♦ All trade data reporting is done by an entity within the company 

that does not have a financial interest in the published index 

(preferably the chief risk officer). 

♦ The company is cooperating fully with any government agency 

investigating its past price reporting practices. 

Chapter IV: Spot Gas Prices 

Were Not the Product of a 

Well Functioning 

Competitive Market—They 

Should be Replaced for the 

California Refund 

Proceeding 

In this and previous chapters of this Report, Staff concludes that 

California spot gas prices were artificially high due to market 

dysfunctions, illiquidity, misreporting, and a rupture causing an 

abnormal pipeline capacity shortage. The spot gas prices reflected 

extraordinary basis differentials that far exceeded the cost of 

transportation and reached levels that would never have been sustained 

in a competitive market. While some portion of these price levels 

reflected legitimate scarcity, we cannot calculate the portion 

attributable to scarcity alone. These inflated gas prices were used in 

the California Refund Proceeding to compute clearing prices for the 

entire electric spot power market. While there is no way to precisely 

replicate the level that spot gas prices would have reached in a 

competitive market, Staff recommends the use of producing-area 

prices plus transportation as a proxy for competitively derived gas 

prices in computing the market-clearing prices in the California 

Refund Proceeding. Over the 9-month refund period, Staff’s proposal 

would reduce gas costs used in the refund formula by $7.03 in 
Executive Summary 

Docket No. PA02-2-000 Price Manipulation in Western Markets ES-9

southern California and $4.18 in northern California, or about $5.60 on 

average. 

Many generators paid these distorted gas prices and fundamental 

fairness dictates that they be able to recover these costs. Accordingly, 

Staff also recommends that generators be made whole for the spot gas 

prices they paid, but that this recovery be on a dollar-for-dollar basis 

and not part of the market-clearing price. 

Staff’s proposal would increase the level of the refunds for California. 

Chapter V: Spot Power 

Prices Adversely Affected 

Long-Term Power Prices 

The vital link between the spot price and forward price for a 

commodity is the ability to store that commodity. In essence, someone 

can meet future needs by purchasing the commodity now and storing it 

for future consumption. As a result, the forward price that someone is 

willing to pay will approximate the cost of purchasing plus the 

carrying cost involved with stockpiling. Since the feasibility of storing 

electricity is very limited, we would expect to see little or no 

relationship between spot electric prices today and the forward price of 

electricity. Instead, forward prices should mostly reflect a buyer’s 

expectations of prices in the future. Since natural gas is the marginal 

fuel in the West, forward gas prices should, in large part, explain 

forward power prices. Our analysis shows, however, that forward 

power prices negotiated during 2000–2001 in the western United 

States were significantly influenced by the then-current spot power 

prices. This tells us that the trauma of the dysfunctional spot power 

prices at that time so influenced buyers that they placed great weight 

on these prices in forming future expectations. The influence of spot 

prices on forward prices was the greatest for forward contracts with 

the shortest time to delivery (1-2 years) and varied by location. While 

Staff has found a statistically significant relationship, the magnitude of 

the impact is limited (that is, the impact of spot power prices on longterm power prices is clearly not dollar-for-dollar). Rather, a reduction 

of about one-third in the price of a 2-year forward contract would 

require a finding that spot power prices were three times above the just 

and reasonable level. 
Executive Summary 

Docket No. PA02-2-000 Price Manipulation in Western Markets ES-10

Chapter VI: Trading 

Strategies, Anomalous 

Behavior, Economic 

Withholding, and Inflated 

Bidding 

In this chapter, we identify various entities that appear to have 

participated in some Enron price manipulation strategies; entered into 

profit-sharing arrangements with Enron, which masked Enron’s realmarket share; engaged in economic withholding; and raised clearing 

prices through inflated bidding. We also find evidence of price 

manipulation of the electric price index at Palo Verde and evidence 

that the spot power prices in the Pacific Northwest were inflated. 

Violations of Cal ISO and Cal PX Tariffs 

Since 1998, the Cal ISO and Cal PX tariffs have contained Market 

Monitoring and Information Protocols (MMIP). The MMIP include 

antigaming and anomalous market behavior provisions that identify 

various abuses and misconduct, such as taking unfair advantage of 

market rules, excessive pricing or bidding, and behavior not consistent 

with competitive markets, to the detriment of the efficiency of 

customers in the Cal ISO and Cal PX markets. 

 

The Cal ISO and Cal PX initially submitted the MMIP (along with 

other protocols) for informational purposes only on October 31, 1997. 

The Commission, however, found that the protocols, including the 

MMIP, “govern a wide range of matters which traditionally and 

typically appear in agreements that should be filed with and approved 

by the Commission.” 3 Therefore, the Commission accepted the 

protocols, including the MMIP, for filing, and directed the Cal ISO 

and Cal PX to post the protocols on their Internet sites and to file the 

complete protocols pursuant to Section 205 of the Federal Power Act 

within 60 days of the Cal ISO’s Operations Date.4

 The Cal ISO and the 

Cal PX made that compliance filing on June 1, 1998. Accordingly, the 

MMIP has been part of the Cal ISO and Cal PX filed rate schedules 

since the Cal ISO’s Operations Date (April 1, 1998). 

Because of the fact that Part 2 of the MMIP specifically enumerates 

suspect practices, that Section 7.3 of the MMIP authorizes the Cal ISO 

to impose “sanctions and penalties” or to refer matters to the 

Commission for appropriate sanctions or penalties, and that the MMIP 

 

3

Pacific Gas and Electric Co., et al., 81 FERC ¶ 61,320 at 62,470-471 (1997). 4

Id. 
Executive Summary 

Docket No. PA02-2-000 Price Manipulation in Western Markets ES-11

is part of the Cal PX’s and Cal ISO’s rate schedules on file with the 

Commission, Staff concludes that entities that transact through the Cal 

PX or Cal ISO and engage in such enumerated practices are in 

violation of those filed rate schedules. The stated objectives of the 

MMIP are to identify abuses of market power by giving particular 

scrutiny to a list of abusive practices and misconduct and to take 

corrective action, including sanctions and penalties. In Staff’s view, 

the identified misconduct remains a violation of the Cal ISO’s and Cal 

PX’s filed rate schedules even if such formal procedures as referral 

outlined in the MMIP did not occur. The Commission can enforce a 

rate schedule on file even when there are processes in that rate 

schedule which, had they been used, would have assisted the 

Commission. Ultimately, the Commission can enforce a tariff with or 

without the assistance of a complaint or referral. 

Orders To Show Cause 

We conclude that many of these behaviors violated the Cal ISO and 

Cal PX tariffs and recommend that these entities be ordered to show 

cause why they should not disgorge revenues and why market-based 

authorizations should not be revoked. This disgorgement would be in 

addition to the refunds in the California Refund Proceeding. 

Spot Power Prices in the Pacific Northwest Appear Inflated 

Staff analysis of actual transaction data for the period January 2001 to 

June 2001 indicates that spot power prices in the Pacific Northwest 

appear to be excessive, as were spot power prices in the California 

portion of the integrated Western market. 

Recommendation for Further Pacific Northwest Proceedings 

Staff recommends that this Report and, in particular, the conclusions 

herein related to the Pacific Northwest spot power prices, be remanded 

to the Administrative Law Judge in Docket No. EL01-10-000. 

Chapter VII: Wash Trading on 

EOL Created a False 

Impression of Liquidity 

Wash trades were common on EOL across many products and 

locations. In fact, EOL often posted its willingness to buy and sell at 

the same price. This invited counterparties to wash trades, and these 

trades created a false sense of liquidity, which can distort prices. 
Executive Summary 

Docket No. PA02-2-000 Price Manipulation in Western Markets ES-12

Enron also manipulated prices on EOL by having affiliates on both 

sides of certain wash-like trades. This created artificial price volatility 

and raised prices. 

Ban Wash Trading and Prohibit Reporting of Affiliate Trades to Indices 

Staff recommends that the Commission establish specific rules 

banning any prearranged trades that wash and prohibiting the reporting 

of affiliate trades to industry indices. 

Chapter VIII: Enron’s Trading 

Practices on EOL Were 

Lucrative 

EOL’s one-to-many platform provided no transparency to the market. 

However, EOL provided Enron with a huge information advantage 

that Enron used to earn large profits. 

EOL was not simply a conduit for transactions earning a moderate but 

steady profit on the spread between what it paid and what it sold. In 

fact, EOL took large positions and was an active, successful 

speculator. Enron used the information advantage acquired from its 

central position in physical markets to earn large speculative profits in 

financial products—more than $500 million in 2000 and 2001. Enron 

could sustain trading losses in the thinner physical markets as the cost 

to gain its information edge, which enabled it to earn large net profits. 

Condition Market-Based Rates and Blanket Gas Certificates 

We recommend that market-based rates and blanket gas certificates be 

conditioned to require sellers who use electronic platforms to use only 

those platforms with certain transparency and monitoring attributes. 

As discussed in this chapter and Chapter IX, Staff recommends that 

these platforms employ various monitoring tools, such as a churn 

alarm, to detect a large amount of buying and selling in a short 

timeframe. 

Staff also recommends that information about all trigger events, e.g., 

identity of the market participants and the transaction data, be made 

available to the Commission through a real-time data feed. 
Executive Summary 

Docket No. PA02-2-000 Price Manipulation in Western Markets ES-13

Chapter IX: Enron 

Manipulated Thin Physical 

Markets for Profit in 

Financial Markets 

Financial energy products are used to hedge risk on physical energy 

products, and the two are interrelated. Physical transaction prices 

dictate the pricing of financial products, i.e., financial products derive 

their value from the underlying physical market. The depth and 

liquidity of financial energy markets are far greater than those of 

physical markets. 

The relationship between financial and physical energy products and 

the relatively thinner and less liquid physical markets provides 

opportunities to manipulate the physical markets and profit in the 

financial markets. This is true regardless of whether the manipulation 

in the physical market raises or lowers prices for the physical 

commodity. 

This Report analyzes an experiment by Enron to test a manipulation 

strategy and an actual manipulation by Enron using EOL. Enron 

manipulated the price of physical gas upward, then downward. 

Although the price change in the physical markets was only about 

$0.10/MMBtu, Enron profited due to the effect that this small change 

in the physical price had on its large financial position. Enron earned 

more than $3 million from this manipulation. 

Show Cause Why the Commission Should Not Revoke Enron’s Gas 

Marketing Certificate 

We recommend that the Commission issue an order directing Enron to 

show cause why it should not have its blanket gas marketing certificate 

revoked. 

Chapter X: Allegations That 

Williams Cornered the 

Market in Southern California 

Gas Are Unsubstantiated 

Staff investigated allegations that Williams Energy Marketing & 

Trading Company cornered the natural gas market in California in 

January 2001. Based on the data, information, and documents 

reviewed, Williams purchased natural gas in amounts roughly 
Executive Summary 

Docket No. PA02-2-000 Price Manipulation in Western Markets ES-14

equivalent to its needs and had a small share of the natural gas 

demand. The allegations that Williams cornered the natural gas market 

in southern California for January 2001 are unsubstantiated. 

Details of Staff 

Recommendations 

Below we identify in one comprehensive list the specifics of Staff’s 

recommendations for the Commission’s consideration in addressing 

the issues arising out of this investigation. Staff recommends that the 

Commission: 

♦ Amend Sections 284.284 and 284.402 of the regulations to provide 

explicit guidelines or prohibitions for trading natural gas under 

Commission blanket certificates. (Chapters II and IX) 

♦ Consider a generic proceeding to develop appropriate reporting 

and monitoring requirements for sellers of natural gas under the 

Commission’s blanket certificates. (Chapters II and IX) 

♦ Condition all electric market-based rates and natural gas blanket 

marketing certificates on the companies providing complete, 

accurate, and honest information to any entity that publishes the 

price indices. (Chapter III) 

♦ Condition all electric market-based rates and natural gas blanket 

marketing certificates on retaining all relevant data and 

information needed to reconstruct a published price index for a 

period of 3 years. (Chapter III) 

♦ Require that any published price indices for Commissionjurisdictional transactions (e.g., pipeline tariff rates, market-based 

electric sales) must be subject to audit to ensure the accuracy of the 

data going in and the calculations themselves. (Chapter III) 

♦ Require that only actual trade data be used to construct the price 

indices. (Chapter III) 

♦ Require that data sent to firms publishing price indices be provided 

by the risk management office of the company, not the trading 

desk or a trader, and be certified by the chief risk officer. 

(Chapter III) 

♦ Encourage standard product definitions for published natural gas 

and electricity price indices and standard methodologies for 

calculating the price indices. (Chapter III) 

♦ Require Dynegy, Aquila, AEP, El Paso Merchant Energy, 

Williams, Reliant, Duke, Mirant, Coral, CMS, and Sempra Energy 
Executive Summary 

Docket No. PA02-2-000 Price Manipulation in Western Markets ES-15

Trading to demonstrate that they no longer sell natural gas at 

wholesale or that: 

 Those employees, including trading desk heads and managers, 

who participated in manipulations or attempted manipulations 

of the published price indices have been disciplined. 

 The company has a clear code of conduct in place for reporting 

price information. 

 All trade data reporting is done by an entity within the 

company that does not have a financial interest in the published 

index (preferably the chief risk officer). 

 The company is cooperating fully with any government agency 

investigating its past price reporting practices. (Chapter III) 

♦ Use producing-area prices plus transportation as a proxy for 

competitively derived gas prices in computing the market-clearing 

prices in the California Refund Proceeding. (Chapter IV) 

♦ Allow generators, many of which paid high gas prices, to recover 

these costs on a dollar-for-dollar basis, but not as part of the 

market-clearing price. (Chapter IV) 

♦ For contracts that are subject to a just and reasonable standard of 

review in the ongoing consolidated complaint proceedings,5 the 

Commission should send this analysis to the Administrative Law 

Judges to use as seen fit to resolve the complaints. (Chapter V) 

♦ Conclude that the Cal ISO and Cal PX tariff antigaming and 

anomalous market behavior provisions identify various abuses and 

misconduct, such as taking unfair advantage of market rules, 

excessive pricing or bidding, and behavior not consistent with 

competitive markets; that these provisions authorize the imposition 

of sanctions and penalties by the Commission; that these 

provisions are part of the Cal ISO and Cal PX rate schedules on 

file; and that entities that engaged in the identified practices 

violated the Cal ISO and Cal PX filed rate schedules. (Chapter VI) 

♦ Conclude that the Commission can enforce a rate schedule on file 

on its own motion without complaint or referral. (Chapter VI) 

 

5

Consolidated proceeding: Nevada Power Company and Sierra Pacific Power 

Company v. Enron Power Marketing, Inc., El Paso Merchant Energy, and American 

Electricity Power Services Corporation; Nevada Power Company v. Morgan Stanley 

Capital Group, Calpine Energy Services, Reliant Energy Services, and Mirant 

Americas Energy Marketing, L.P.; Southern California Water Company v. Mirant 

Americas Energy Marketing, L.P.; and Public Utility District No. 1, Snohomish 

County, Washington v. Morgan Stanley Capital Group, Inc.—Docket Nos. EL02-28-

000, EL02-33-000, EL02-38-000, EL02-29-000, EL02-30-000, EL02-32-000, EL02-

34-000, EL02-39-00, EL02-43-000, and EL02-56-000. 
Executive Summary 

Docket No. PA02-2-000 Price Manipulation in Western Markets ES-16

♦ Apply these provisions in issuing and implementing various show 

cause orders. (Chapter VI) 

♦ Explicitly prohibit the use of false information as a condition for 

granting all market-based rate authorizations and blanket gas 

marketing certificates and add this condition to all open access 

transmission tariffs. (Chapter VI) 

♦ Direct certain market participants identified in the January 6, 2003 

Cal ISO Report6

 to show cause why their behavior did not 

constitute gaming in violation of the Cal ISO and Cal PX tariffs, 

with disgorgement of unjust profits associated with the violations 

or other appropriate remedies. (Chapter VI) 

♦ Direct AES/Williams, Dynegy/NRG, Mirant, Reliant, BPA, 

LADWP, Idaho Power, Powerex, and Enron to show cause why 

their prices from May to October 2000 did not constitute economic 

withholding or inflated bidding in violation of the antigaming and 

anomalous market behavior provisions in the Cal ISO and Cal PX 

tariffs, with disgorgement of unjust profits associated with the 

violations or other appropriate remedies. (Chapter VI) 

♦ Issue an order to Enron and the entities with whom it jointly 

engaged in the Enron trading strategies7

 (both public utilities and 

governmental entities) to show cause why this did not constitute 

gaming in violation of the Cal ISO and Cal PX tariffs, with 

disgorgement of unjust profits associated with the violations or 

other appropriate remedies. (Chapter VI) 

♦ Issue an order for Enron to show cause why its market-based rate 

authorization and its blanket gas marketing certificate authority 

should not be revoked. (Chapters VI and IX) 

 

6

Sempra/San Diego Gas and Electric; Morgan Stanley Capital Group; Coral Power, 

LLC; Powerex Corporation; Enron Power Marketing, Inc.; Enron Energy Services 

Inc.; Avista Energy Inc.; Pacific Gas and Electric Company; American Electric 

Power Services Corporation; Duke Energy Trading and Marketing; Mirant; CargillAlliant, LLC; Idaho Power Company; Puget Sound Energy; Dynegy; PGE Energy 

Services; Calpine Corporation; Modesto Irrigation District; City of Glendale, 

California; Arizona Public Service Company; Williams Energy Services 

Corporation; PacifiCorp; Automated Power Exchange; Bonneville Power 

Administration; Portland General Electric; Los Angeles Department of Water and 

Power; Aquila; Southern California Edison; Citizens Power Sales; Constellation 

Power Service; Sierra Pacific; Azusa; Riverside; Pasadena; Vernon; Salt River 

Project; and Reliant. 

7

Energy West; Montana Power Company; Puget Sound Power and Lighting 

Company; Powerex Corporation; City of Redding, California; City of Glendale, 

California; Colorado River Commission; Las Vegas Cogeneration; Washington 

Water Power Company (later named Avista); Valley Electric Association; Public 

Service of New Mexico; Grant Public Utility District; Grays Harbor Paper Company; 

Modesto Irrigation District of Northern California; and TOSCO. 
Executive Summary 

Docket No. PA02-2-000 Price Manipulation in Western Markets ES-17

♦ Order all jurisdictional entities to file any agreements with other 

entities that have any of the characteristics of the Enron joint 

partnership arrangements within 30 days. (Chapter VI) 

♦ Order Reliant and BP Energy to show cause why their authorities 

to sell power at market-based rates should not be revoked by the 

Commission due to manipulation of electricity prices at Palo 

Verde. (Chapter VI) 

♦ Remand this Report and, in particular, the conclusions herein 

related to the Pacific Northwest spot power prices, to the 

Administrative Law Judge in Docket No. EL01-10-000. 

(Chapter VI) 

♦ Establish specific rules banning any form of prearranged wash 

trading and prohibiting the reporting of any affiliate trading 

activities through industry indices. (Chapter VII) 

♦ Condition blanket gas marketing certificates, as well as electric 

market-based rates, to require that sellers who use trading 

platforms use only those trading platforms that agree to provide the 

Commission with full access to trade reporting and order book 

information for the trading systems and agree to adhere to 

appropriate monitoring requirements. (Chapters VII, VIII, and IX) 

♦ Recommend that Congress consider giving direct authority to a 

Federal agency to ensure that electronic trading platforms for 

wholesale sales of electric energy and natural gas in interstate 

commerce are monitored and provide market information that is 

necessary for price discovery in competitive energy markets. 

(Chapters VII, VIII, and IX) 

♦ State that the allegations that Williams Energy Marketing & 

Trading Company cornered the natural gas market in California in 

January 2001 are unsubstantiated. (Chapter X) 

♦ Reevaluate the “simultaneous offer” rule that it uses to discipline 

affiliate transactions to ensure that it is effective and verifiable. 

(Initial Report) 

♦ Require that all market-based rate tariffs include a specific 

prohibition against the submission of false information or the 

omission of material information to the Commission or to an entity 

such as an independent system operator, a regional transmission 

organization, or an approved market monitor. (Initial Report) 

♦ Recommend that Congress expand the Commission’s civil penalty 

authority that applies to jurisdictional companies that violate 

Commission orders, regulations, or tariffs. (Initial Report) 
Chapter I 

Docket No. PA02-2-000 Price Manipulation in Western Markets I-1

I. Manipulations in the California Natural Gas Spot Markets 

Forced Upward Pressure on Wholesale Electric Prices 

California experienced extraordinarily high wholesale electric prices 

from the summer of 2000 through the winter of 2000–2001. High 

natural gas prices in California from the summer of 2000 through the 

winter of 2000–2001, in combination with accelerated electric 

demand, generation failures, flawed regulation, and transmission 

constraints combined to create these extraordinary wholesale electric 

prices. Gas-fired generation units, particularly peaking units, were 

often reliant on the spot gas market, due in part to policies of the 

California Public Utilities Commission (CPUC) that restricted their 

ability to enter into long-term contracts for natural gas. Operators of 

gas-fired generation units in California who paid higher spot market 

gas costs consequently raised their bids in the wholesale spot electric 

market. The effect of relatively inefficient generators (i.e., those with 

high heat rates), whose bids set the market price for all sellers, was to 

increase the impact of higher gas prices on wholesale electric prices. 

Higher gas prices increased the revenues owed to power sellers and 

ultimately severely affected the state’s electric customers. 

While soaring demand for natural gas and flawed electric power 

market rules were the primary drivers of high gas prices, spot market 

manipulations contributed significantly. High wholesale electric prices 

were partially the result of specific behavior inimical to the efficient 

operation of a liquid and transparent competitive market. 

Staff concludes that commodity trading in gas, particularly in southern 

California in the roughly 9-month period beginning in the summer of 

2000, affected the very high electric prices. This conclusion is 

particularly germane to the methodology the Commission established 

in its July 25, 2002 Order to calculate potential refunds due to 

customers in the organized markets operated by the California ISO and 

the California PX for the period October 2, 2000 through June 20, 

2001.1 In that Order, the Commission established a mitigated price 

based on the marginal cost of the last unit dispatched to meet load in 

the California ISO’s real-time market based on a daily spot gas price, 

as published in Financial Times Energy’s Gas Daily publication. 

We conclude that reliance on published spot market prices for natural 

gas at California delivery points is inappropriate for calculating 

 

1

See San Diego Gas & Electric Company v. Sellers of Energy and Ancillary Service, 

96 FERC ¶ 61,120 at 61,499, 61,516-517 (2001). 
Chapter I 

Docket No. PA02-2-000 Price Manipulation in Western Markets I-2

market-clearing power prices. In particular, these published prices 

reflect anomalous outcomes and manipulative activities not associated 

with a competitive market. Accordingly, they should not provide the 

basis for potential refunds to electric customers. 

Sellers of wholesale power obtained prices that were augmented in an 

amount greater than the addition of higher gas input costs alone 

because, as indicated above, the market clearing price was set by the 

marginal (i.e., least efficient) unit. Thus, while sellers may have 

incurred higher spot market input costs for their gas-fired generation 

units, they obtained wholesale electric prices that magnified the effect 

of these higher gas costs because all generators were paid a single 

clearing price. Use of published gas index prices would result in a 

windfall to sellers if the published spot market prices for natural gas 

were used in the refund methodology.2 Gas costs that were inflated by 

conditions not associated with competitive markets should not provide 

a source of profit to wholesale power sellers. Staff urges a different 

methodology for calculating electric prices for this period of market 

dysfunction. 

Spot Market Natural Gas 

Prices at California Borders 

Were Extraordinarily High 

 

Sharply higher gas costs beginning in the summer of 2000 and 

extending through the winter of 2000–2001 exacerbated already dire 

conditions for electric customers in California. Increased gas 

consumption pressured prices upward. Gas consumed for electric 

generation in California increased by 44 percent from May 2000 

through October 2000, as compared to 1999 levels during the same 

period. In the entire West, the increase was 46 percent.3

 California’s 

electric sector used 1.1 Tcf of gas in 2000, a 22-percent increase over 

consumption in 1999.4

 Total annual gas-fired generation in California 

 

2

Stated alternatively, since many sellers of wholesale power obtained electricity from 

relatively efficient generating units, these sellers realized a net producers’ surplus; 

i.e., the difference between the minimum price at which the seller would be willing 

to sell power and the amount for which it actually sold. See Varian, Hal R., 

Intermediate Microeconomics (New York: W.W. Norton & Co., 1987), pp. 262–263. 

In a competitive market, producer surplus is a justified return earned by more 

efficient suppliers. However, because input prices were inflated due in part to 

manipulation, the associated producer surplus was also artificially inflated and hence 

the portion due to manipulation is unjustified. Staff cannot calculate the portion of 

the prices due to manipulation. 

3

Electric Power Monthly, Energy Information Administration, January 2001.

4

Electric Power Annual, Energy Information Agency, p. 8 (Internet pagination). 
Chapter I 

Docket No. PA02-2-000 Price Manipulation in Western Markets I-3

rose by 31.7 percent in 2000, as compared to 1999 levels.5 As noted 

above, gas-fired generators were willing to incur increased costs 

because they could pass these costs through in the form of higher 

charges for their outputs. Inefficient gas-fired units were called on by 

the California ISO to run to avoid power blackouts and this resulted in 

higher wholesale electric prices. 

Higher demand was not the only driver of higher gas prices. In the 

August 2002 Initial Report, the Staff observed that spot market prices 

at the Southern California Border were detached from production 

basin prices; this indicates that transportation constraints contributed to 

a scarcity of gas supply relative to demand in the area, contributing to 

higher gas costs for California customers. Since the Commission 

regulates the maximum rate for transportation of natural gas by 

interstate pipelines, given sufficient interstate pipeline capacity and 

sufficient storage utilization, the cost of gas at the California border 

should not have significantly exceeded the production basin price of 

the gas plus the interstate transportation charge, unless scarcity and 

nonregulatory factors drove the imbalance.6

 

 

5

“U.S. Natural Gas Markets: Mid-Term Prospects for Natural Gas Supply,” Energy 

Information Administration (December 2001), p. 13 (Internet pagination). 6

As the Commission has explained, its jurisdiction to regulate the prices charged by 

sellers of natural gas is subject to statutory limitations: 

The Natural Gas Policy Act of 1978 (NGPA) and the Natural Gas Wellhead 

Decontrol Act substantially narrowed the Commission’s Natural Gas Act 

(NGA) jurisdiction over sales for resale, with the Wellhead Decontrol Act 

removing all “first sales” from the Commission’s NGA jurisdiction as of 

January 1, 1993. First sales include all sales other than those by interstate or 

intrastate pipelines, LDCs, or their affiliates. In addition, Section 3(b) of the 

NGA provides that all sales of gas imported from countries with free trade 

agreements, such as Canada and Mexico, have first sale status even when 

sold by pipelines, LDCs, or affiliates. The end result of these various 

statutory provisions is that the only sales the Commission currently has 

jurisdiction to regulate are those for resale of domestic gas by pipelines, 

LDCs, or their affiliates. 

Reporting of Natural Gas Sales to the California Market, 95 FERC ¶ 61,262 at 

61,929 (2001) (footnotes omitted). In addition, in 1992, the Commission directed 

pipelines to separate their transportation and commodity sales services. See Order 

No. 636, FERC Stats. & Regs., Regulations Preambles (January 1991 to June 1996) 

¶ 30,939 (1992). By unbundling these products, pipelines became more like common 

carriers. This reform, among others, increased efficiency by creating a largely 

transparent interstate transportation market in which pipelines were required to treat 

all shippers equally. According to one authority, natural gas prices have been lower 

since Federal deregulation of natural gas prices, although the volatility of those 

prices has increased. “Natural Gas: Analysis of Changes in Market Price,” General 

Accounting Office, December 2002, p. 10. 
Chapter I 

Docket No. PA02-2-000 Price Manipulation in Western Markets I-4

California has separate natural gas markets in southern and northern 

California. The markets are separate because of limits on 

transportation capacity between the regions and, therefore, prices are 

often different in the respective regions. In southern California, limited 

transportation capacity and storage contributed to higher gas prices in 

the 2000–2001 period than in the prior year. In northern California, 

fewer transportation constraints, greater storage, and the ability of 

generators to hold firm transportation capacity resulted in lower spot 

market prices for natural gas. Although we discuss southern California 

and northern California natural gas prices and market conditions 

separately, our overall point is that dysfunctions in both regions render 

spot prices inappropriate as bases for electric refund calculations. 

Most large natural gas customers in southern California, such as 

electric generation plants, could (1) buy bundled gas at the Southern 

California Border or (2) buy gas at the San Juan or Permian production 

basins (located roughly in the Four Corners area and west Texas, 

respectively) and arrange for transportation of the gas by interstate 

pipeline to the Southern California Border.7

 There would have been 

little reason to pay spot prices at the Southern California Border that 

exceeded the cost of natural gas purchased in one of the production 

basins plus the cost of transportation to the border, unless 

transportation was not readily available. 

The CPUC’s regulation of Southern California Gas Company 

(SoCalGas) impacted terms under which interstate pipeline capacity 

was purchased. For example, the CPUC limited SoCalGas to 

purchasing interstate pipeline capacity necessary to serve its core 

customers, which did not include independent generators. The CPUC 

also approved terms of service on SoCalGas’ system that, for example, 

did not provide for firm transportation service on SoCalGas for 

independent generators. These aspects of the CPUC’s regulation did 

not change the generators’ option of buying at a production basin and 

shipping gas to the border (to the extent that interstate capacity was 

available) or buying a bundled product at the border. No matter which 

option generators elected, they would have been able to obtain 

transportation to their burner tips because, as a rule, SoCalGas 

delivered gas for shippers that had firm rights on an upstream 

interstate system or that purchased gas from shippers having firm 

rights on an upstream system. Williams Energy Marketing & Trading 

 

7

Approximately 83 percent of the natural gas California consumes is transported 

from out of state. “U.S. Natural Gas Markets: Mid-Term Prospects for Natural Gas 

Supply,” Energy Information Administration (December 2001), p. 13 (Internet 

pagination). Thus, traders and customers of natural gas rely principally on out-ofstate gas to meet the demands of California users. 
Chapter I 

Docket No. PA02-2-000 Price Manipulation in Western Markets I-5

Company is an example of a firm that chose both options: To satisfy 

contracts to supply generators in southern California, it bought 

producer gas and shipped it to the border and it also purchased bundled 

gas at the border. Accordingly, the fact that SoCalGas did not offer 

firm transportation to generators did not affect the generators’ basic 

option of buying at a production basin and transporting to the border or 

buying bundled supplies. 

Natural gas spot prices at the Southern California Border were 

historically high in the summer of 2000 and the winter of 2000–2001 

(see Figure I-1). For example, the price of natural gas for residential 

customers in California averaged $12.10/Mcf in January 2001, a 90-

percent increase from January 2000.8

 

Natural gas spot prices at the Southern California Border were also 

high relative to Henry Hub prices and the prices at other major trading 

centers. The persistent basis differentials experienced at the Southern 

California Border, given the presence of transportation that is rate 

 

8

“Electricity Shortage in California: Issues for Petroleum and Natural Gas Supply,” 

Energy Information Administration, June 2001, p. 8 (Internet pagination). 

Spot Natural Gas Prices at SoCal for the periods

July 1999 - March 2000 & July 2000 - March 2001

0

10

20

30

40

50

60

70

1-Jul 1-Aug 1-Sep 1-Oct 1-Nov 1-Dec 1-Jan 1-Feb 1-Mar

July 1999 to March 2000 July 2000 to March 2001

Figure I-1 

Spot Natural Gas Prices at SoCal for the Periods 

July 1999 – March 2000 and July 2000 – March 2001 
Chapter I 

Docket No. PA02-2-000 Price Manipulation in Western Markets I-6

regulated by the Commission, suggest a dysfunctional gas market. 

Table I-1 presents a range of data at various locations.9

 

Table I-1. Various Delivered Natural Gas Prices 

Figure I-2 depicts the radical decoupling of Henry Hub and SoCal 

average spot natural gas prices on a monthly average basis. Figure I-3 

suggests a rough correlation between production basin and SoCal 

border prices in the period July 1999 through March 2000. Figure I-4 

shows production basin and SoCal border prices for the period July 

2000 through March 2001. This shows that prices diverged 

substantially starting in November 2000. 

Prices were also high at the northern California border relative to 

production basin prices (see Figures I-5 and I-6). Part of the reason for 

this price differential was that gas from the San Juan basin, normally 

an attractive source of supply for central California, was diverted to 

the southern California market because of the high prices for spot gas 

at the Southern California Border. Accordingly, the price at Pacific 

Gas and Electric Company (PG&E) citygate reflected the fact that the 

supply from southern California was less than it had been previously. 

Increased demand also contributed significantly to the high basin 

differentials in northern California. 

 

9

“U.S. Natural Gas Markets: Recent Trends and Prospects for the Future,” Energy 

Information Agency, May 2001, p. x; RDI GasDat (for PG&E citygate only). 

Quarter and Year Henry Hub

Chicago 

Citygate 

Florida 

Citygate 

New York 

Citygate 

SoCal 

Citygate 

PG&E 

Citygate 

3rd quarter 2000 4.47 4.56 5.00 4.81 5.28 5.10 

4th quarter 2000 6.41 6.82 6.73 8.07 13.59 12.27 

1st quarter 2001 6.44 6.61 6.85 7.83 15.19 10.28 
Chapter I 

Docket No. PA02-2-000 Price Manipulation in Western Markets I-7

Daily Spot Natural Gas Prices at Selected Basin & SoCal

July 1999 - March 2000

0

0.5

1

1.5

2

2.5

3

3.5

1-Jul-99 1-Aug-99 1-Sep-99 1-Oct-99 1-Nov-99 1-Dec-99 1-Jan-00 1-Feb-00 1-Mar-00

SAN JUAN PERMIAN SOCAL

Figure I-3 

Daily Spot Natural Gas Prices at Selected Basins and SoCal 

July 1999 – March 2000 

Monthly Average Spot Gas Prices at Henry Hub & SoCal

0

5

10

15

20

25

30

Jul-00 Aug-00 Sep-00 Oct-00 Nov-00 Dec-00 Jan-01 Feb-01 Mar-01

Henry Hub SoCal

Figure I-2 

Monthly Average Spot Gas Prices at Henry Hub and SoCal 
Chapter I 

Docket No. PA02-2-000 Price Manipulation in Western Markets I-8

Daily Gas Prices at San Juan, El Paso Permian Basin & Socal

July 2000 - March 2001

0

10

20

30

40

50

60

70

Jul-00 Aug-00 Sep-00 Oct-00 Nov-00 Dec-00 Jan-01 Feb-01 Mar-01

San Juan El Paso Permian SoCal

Figure I-4 

Daily Gas Prices at Selected Basins and SoCal 

July 2000 – March 2001 

Daily Spot Gas Prices at Main Canadian Production Point & PG&E

July 1999 - March 2000

0

0.5

1

1.5

2

2.5

3

3.5

4

1-Jul-99 1-Aug-99 1-Sep-99 1-Oct-99 1-Nov-99 1-Dec-99 1-Jan-00 1-Feb-00 1-Mar-00

Main Canadian Production Point PG&E

Figure I-5 

Daily Natural Spot Gas Prices at Main Canadian Production Point (NOVA (AECO-C)) and PG&E

July 1999 – March 2000 
Chapter I 

Docket No. PA02-2-000 Price Manipulation in Western Markets I-9

Daily Spot Natural Gas Prices at Main Canadian Production Point & PG&E

July 2000 - March 2001

0

10

20

30

40

50

60

70

5-Jul-00 5-Aug-00 5-Sep-00 5-Oct-00 5-Nov-00 5-Dec-00 5-Jan-01 5-Feb-01 5-Mar-01

Main Canadian Production Point PG&E

Supply/Demand Imbalance 

and Flawed Market Rules 

Drove Wholesale Electric 

Prices Higher During 2000 

and 2001 

In November 2000, the Commission determined that the electric 

market structure and market rules for wholesale sales of electric 

energy in California were seriously flawed in the summer of 2000.10

This determination stemmed ineluctably from the wholesale prices in 

California observed during the preceding half-year. This section 

surveys the major factors that blighted California’s wholesale electric 

markets from the summer of 2000 through the winter of 2000–2001. 

Overall, the significant increase in power production costs was 

triggered by increased demand, significant demand inelasticity, and a 

scarcity of available generation resources throughout much of the 

West. Further, California’s existing market rules exacerbated 

conditions by exposing the state’s three investor-owned utilities to the 

volatility of the wholesale spot market without affording them the 

ability to mitigate price volatility and by promoting underscheduling in 

the PX. 

 

10San Diego Gas & Electric Company v. Sellers of Energy and Ancillary Services 

(San Diego), 93 FERC ¶ 61,121 at 61,349 (2000). 

Figure I-6 

Daily Spot Natural Gas Prices at Main Canadian Production Point (NOVA (AECO-C)) and PG&E

July 2000 – March 2001 
Chapter I 

Docket No. PA02-2-000 Price Manipulation in Western Markets I-10

Weather Extremes and High Demand 

The August 2002 Interim Staff Report noted weather extremes and 

high demand in California during 2000 and 2001. 

From June through August 2000, California experienced one of the 

hottest summers in 106 years of recordkeeping.11 In November, 

average temperatures were unusually low. This atypical weather 

helped drive load growth in California as temperature-sensitive 

residential customers, in particular, increased their demand. California 

generators alone produced 414,094 million kWh in 2000, as compared 

to 383,169 million kWh in 1999.12 

Reduced snow pack from the winter and lower rainfall in the summer 

of 2000 reduced western area hydropower output, which California has 

traditionally relied on to meet its hot-weather peak. Net generation 

from hydroelectric sources in Washington produced 81 billion kWh in 

2000, down from 97 billion kWh in 1999, and net generation from 

hydroelectric sources in Oregon produced 38 billion kWh in 2000, 

down from 46 billion kWh in 1999.13 On a broader scale, hydroelectric 

generation in the Northwest was 14 percent lower in 2000 than in 

1999, which amounts to a reduction of 46.4 million MWh in total 

Northwest generation.14 Within California, reduced hydropower 

availability forced greater reliance on in-state, gas-fired generation, 

sourced from units that were generally old and relatively inefficient. 

Stepped-up demand and low hydropower increased reliance on gasfired generation, raising the demand for and the price of spot market 

gas. As one authority summarized, “[b]etween late 2000 and mid-2001 

... a rapid increase in natural gas demand, brought about by a need to 

increase electricity output from gas-fired power plants (to compensate 

for decreased availability of hydropower), also created a tight market 

for natural gas interstate and intrastate pipeline capacity.”15 Noting that 

“[h]igh electricity prices also reflect reduced Northwest hydropower 

production due to low rainfall and the generally overstressed state of 

 

11Electric Power Annual 2000, Volume I, Preface, Energy Information 

Administration, p. 6 (Internet pagination). 

12Net Generation by Census Division and State, 2000 and 1999, Energy Information 

Administration, p. 2 (Internet pagination). 

13These were approximately 15-percent declines. Electric Power Annual, Volume I, 

Preface, Energy Information Administration, p. 10 (Internet pagination). 

Washington’s 1997 hydroelectric generation peaked at 104 billion kWh and 

Oregon’s 1997 hydroelectric generation peaked at 46 billion kWh. Washington and 

Oregon are California’s principal out-of-state sources for hydroelectric power. 

14“U.S. Natural Gas Markets: Mid-Term Prospects for Natural Gas Supply,” Energy 

Information Administration (December 2001), p. 13 (Internet pagination). 15“Natural Gas Transportation—Infrastructure Issues and Operational Trends,” 

Energy Information Administration (October 2001), p. 15 (Internet pagination). 
Chapter I 

Docket No. PA02-2-000 Price Manipulation in Western Markets I-11

the western power grid,” one commenter concluded that “much 

costlier natural gas has in turn helped to drive up the operating cost of 

electric generation.”16 

Sellers of power necessarily relied on older, relatively inefficient units 

to meet the higher demand or on peaking units that have relatively 

high running costs. These units were run more frequently, and stressed 

more, than they had been in the recent past. Consequently, outages of 

gas-fired units increased in the summer of 2000 in California as 

compared to the previous summer. These outages reduced the supply 

necessary to meet demand. Secretary of Energy Richardson cited “a 

shortage of currently operational electric generation facilities, a 

shortage of water used to generate electricity, [and] unusual volatility 

of electricity and natural gas markets” as reasons supporting his 

finding of an emergency in California “by reason of the shortage of 

electric energy.”17 

Notwithstanding the increased demand and reduced availability of 

hydropower, California exported more power to neighboring states in 

the summer of 2000 than it did in 1999. For example, August 2000 

exports averaged 3,136 MW above the August 1999 level. Higher 

exports reduced that amount of power bid into the day-ahead market. 

In August 2000, price caps in California were reduced to $250/MW, 

down from $500/MW in July and early August and $750/MW in 

June.18 The lower price caps motivated sales of bulk power at higher 

prices outside California, where price caps did not apply. 

Higher demand intensified transmission congestion, which in turn 

contributed to higher wholesale electric prices. While on-peak 

congestion at the California-Oregon border decreased substantially 

from the summer of 1999 to the summer of 2000, on-peak congestion 

north to south on Path 15 increased from 1 percent to 7.9 percent and 

increased from 0 percent to 29.2 percent on Path 26. Off-peak 

congestion from south to north on Path 15 also increased from 28.1 

percent to 49.6 percent. 

 

16Cavanagh, R., “Revisiting ‘the Genius of the Marketplace’: Cures for the Western 

Electricity and Natural Gas Crises,” The Electricity Journal (June 2001), pp. 11 and 

13. 

17Order Pursuant to Section 202(c) of the Federal Power Act, U.S. Department of 

Energy (December 14, 2000). See also, Order Pursuant to Section 202(c) of the 

Federal Power Act, U.S. Department of Energy (January 11, 2001) (citing same 

reasons). 

18San Diego Gas & Electric Company v. Sellers of Energy and Ancillary Services, 

93 FERC ¶ 61,121 at 61,353 (2000). 
Chapter I 

Docket No. PA02-2-000 Price Manipulation in Western Markets I-12

Flawed Market Rules and 

Regulatory Policies 

Magnified Adverse 

Conditions 

California’s then-prevailing regulatory scheme forbade much forward 

contracting by the state’s three largest investor-owned utilities (IOUs). 

The three California IOUs were required to purchase power through 

the PX with little or no ability to purchase through forward contracts, 

exposing the utilities to the volatility of the spot market without the 

ability to mitigate that volatility. Even the generation that was not 

divested by the three California IOUs could not be used directly to 

self-supply their retail load. Under the California market design, this 

retained generation had to be bid into the spot market. The California 

IOUs were required to buy the output of their resources to supply their 

retail customers. In its December 15, 2000 Order, the Commission 

eliminated this aspect of the California market design that required that 

the IOUs must sell all of their generation into, and buy all of their 

energy from, the California PX.19 

A second market design flaw was the lack of demand responsiveness. 

This flaw was exacerbated by a retail rate freeze that insulated 

residential customers from high wholesale prices, thereby thwarting 

the ability of price signals to shape and limit demand. 

A third major flaw was the underscheduling of load by the three 

California IOUs. Economic incentives to underschedule tended to 

increase during high demand periods, which created operational and 

reliability problems for the Cal ISO and required it to obtain out-ofmarket energy at high prices. In its December 15, 2000 Order, the 

Commission established penalties for underscheduling load. 

As a result of the conditions and market rules noted above, hourly 

prices in the PX reached as high as $750/MWh twice in May and eight 

times in June; average prices were $47/MWh in May, $120/MWh in 

June, $106/MWh in July, and $166/MWh in August.20 These prices 

were vastly higher than year-ago prices. For example, the monthly 

average unconstrained market-clearing price for May 2000 in the PX’s 

day-ahead market represented a 100-percent increase over May 

1999.21 

 

19San Diego Gas & Electric Company v. Sellers of Energy and Ancillary Services, 

93 FERC ¶ 61,294 (2000). 

20San Diego, 93 FERC at 61,353 (citing an ISO source); Staff Report to the Federal 

Energy Regulatory Commission on Western Markets and the Causes of Summer 

2000 Price Abnormalities (2000 Western Markets Staff Report), p. 5-1. 21San Diego, 93 FERC at 61,353 (citing a PX source). 
Chapter I 

Docket No. PA02-2-000 Price Manipulation in Western Markets I-13

Finally, emission compliance costs also increased markedly in the 

summer of 2000. The cost of credits for complying with nitrous oxide 

standards rose from approximately $6 per pound in May 2000 to $35 

per pound in August. Because a combined-cycle gas generator 

typically emits from 1 to 1.5 pounds of nitrous oxide per MWh, these 

increased costs were significant. 

Gas market rules were also flawed. In particular, the CPUC’s rules did 

not require that storage facilities be filled during the nonpeak season, 

as discussed in greater detail below. The lack of stored gas in southern 

California contributed to higher border prices in the winter of 2000–

2001. 

 

Transportation Constraints 

and Spot Market 

Dysfunctions Contributed 

Significantly to Higher Spot 

Market Natural Gas Prices at 

the California Border 

The disparity in prices between the primary production basins that 

serve southern California, Permian and San Juan, and the spot market 

price at Topock, Arizona, near the Southern California Border, 

suggests that natural gas transportation between these points was 

constrained. 

Three major interstate pipelines serve southern California. Table I-2 

indicates the limited choices available to gas purchasers for purchasing 

gas for resale or consumption in southern California. 

Table I-2. Interstate Pipeline Design Capacity to California 

Pipeline Design Capacity to California (MMcf/d) 

El Paso Natural Gas Company 3,290 

Transwestern Pipeline Company 1.090 

Kern River 700 

Total Design Capacity 5,080 

A rupture occurred on El Paso Natural Gas Company’s (El Paso’s) 

pipeline in southeast New Mexico in August 2001; capacity was 

immediately reduced by approximately 1 Bcf/d for about 2 weeks 
Chapter I 

Docket No. PA02-2-000 Price Manipulation in Western Markets I-14

following the rupture.22 During the winter of 2000–2001, El Paso 

operated its pipelines immediately upstream and downstream of the 

rupture site at reduced pressures pursuant to an Order of the U.S. 

Department of Transportation.23 Operation at reduced pressure caused 

a reduction in El Paso’s capacity in the amount of 270 MMcf/d during 

this time.24 The loss of capacity was “a major shock to supplies of 

natural gas in the Western Region, particularly in California, Arizona, 

and New Mexico.”25 The amount of gas needed to serve 1 million 

homes is approximately 270 MMcf/d. 

High spot prices in southern California were reflected in the 

willingness of some shippers to pay more than the maximum tariff rate 

for transportation on pipelines serving southern California.26 The 

following table provides a barometer of pipeline capacity scarcity. It 

shows that shippers were able to release capacity on El Paso’s and 

Transwestern Pipeline Company’s (Transwestern’s) systems above the 

maximum tariff rate.27

 

22“Status of Natural Gas Pipeline System Capacity Entering the 2000–2001 Heating 

Season,” Energy Information Administration (October 2000), p. xviii (Internet 

pagination). 

23See Corrective Action Order, issued by the Research and Special Programs 

Administration of the U.S. Department of Transportation, CPF No. 420001004-H 

(August 23, 2000). 

24El Paso press release, October 23, 2002. 

25“Status of Natural Gas Pipeline System Capacity Entering the 2000–2001 Heating 

Season,” Energy Information Administration (October 2000), p. xviii (Internet 

pagination). 

26In Order No. 637, the Commission temporarily removed the rate ceiling for shortterm capacity release transactions. The Commission explained that “[d]uring peak 

demand periods, when capacity is at a premium, the need to provide shippers with 

the greatest number of potential options and the most efficient competitive 

marketplace is crucial. Shippers that most need capacity during periods of scarce 

supply need a market that can efficiently respond to their demands and provide the 

capacity they need.” FERC Stats. & Regs, July 1996 – December 2000 ¶ 31,091 at 

31,270 (2000). While this provision of Order No. 637 expired on September 30, 

2002, 18 C.F.R. § 284.8(i) (2002), it was effective during the winter of 2000–2001. 

27San Diego Gas & Electric Company, 95 FERC ¶ 61,264 (2001) (Appendix). 
Chapter I 

Docket No. PA02-2-000 Price Manipulation in Western Markets I-15

Table I-3. Capacity Releases Above the Maximum Tariff Rate 

Month Pipeline Amount Released Above 

Maximum Rate (MMBtu/d)28

November 2000 El Paso 33,800 

December 2000 El Paso 7,000 

January 2001 El Paso 12,500 

January 2001 Transwestern 7,766 

February 2001 El Paso 19,269 

March 2001 El Paso 34,566 

As the Commission pointed out in an order addressing the data in 

Table I-3, the volumes of released capacity above the maximum tariff 

were not large relative to the total capacity serving California.29

Nonetheless, the data provide an indication of the persistence of 

capacity scarcity because they show that some shippers were willing to 

pay above-tariff prices to avoid paying high bundled prices at the 

California border. The volumes of released capacity may have been 

relatively low, not because a market for capacity above the maximum 

tariff rate did not exist, but because shippers holding capacity wanted 

to use it themselves to transport gas to the California border rather than 

release that capacity to other shippers. 

In short, demand for interstate pipeline capacity and capacity from the 

border into California exceeded supply. Border prices would not have 

exceeded production basin prices as dramatically as they did had there 

been sufficient transportation capacity to meet all of the gas demanded 

by customers in southern California. 

Low storage levels contributed to higher prices and greater volatility in 

the gas market in southern California. If the CPUC rules required that 

storage facilities be filled, gas supplies would have been increased 

during the winter of 2000–2001. Shippers use storage during peak 

periods to supplement interstate pipeline deliveries. Storage levels 

were historically low approaching and during the winter of 2000–

2001. California began the 2000–2001 winter season with 152 Bcf in 

storage, which was 34 Bcf below the 5-year (1995–1999) average.30

By mid-February 2001, California’s working gas inventories were 

estimated at less than 70 Bcf, as compared to the 1995–1999 average 

of 100 Bcf for the end of March.31 

 

28An MMBtu is roughly equal to an Mcf. 

29San Diego, 95 FERC at 61,934-935. 

30“U.S. Natural Gas Markets: Recent Trends and Prospects for the Future,” Energy 

Information Agency, May 2001, p. 22. 

31“U.S. Natural Gas Markets: Recent Trends and Prospects for the Future,” Energy 

Information Agency, May 2001, p. 23.
Chapter I 

Docket No. PA02-2-000 Price Manipulation in Western Markets I-16

Storage levels were low for several reasons. First, the Carlsbad rupture 

caused shippers to draw down storage inventories in August that 

would otherwise have been available for the winter heating season.32

Second, natural gas prices above the historical average in southern 

California in the summer of 2000 caused market participants to reduce 

the amount of gas they put in storage. These market participants 

believed that gas prices would moderate, permitting them to fill 

storage later in the season or purchase natural gas on the spot market at 

lower prices.33

Additional factors, including higher gas-fired generation output due to 

low hydropower availability, nuclear plant outages in November 2000, 

and unusually cold temperatures in November 2000, contributed to the 

drawdown of storage serving southern California customers.34 

Many of the market participants that sold natural gas at the Southern 

California Border during the winter of 2000–2001 were trading 

companies that engaged in major business activities outside of 

California. However, handwritten daily transaction sheets that 

Southern California Gas Company (SoCalGas), a local distribution 

company,35 provides each month to the CPUC indicate that SoCalGas 

profited significantly from border sales at elevated prices. These 

records show, for example, that for the flow date December 12, 2000, 

a date on which natural gas prices at the California border were 

extraordinarily high, SoCalGas purchased gas for approximately $11 

from production area sources and sold gas at Topock for as much as 

$65. For the flow dates February 10 through 12, 2001, the days 

preceding a run-up of border prices, SoCalGas purchased gas at an 

average price of less than $14. From February 14 through 16, when 

gas prices were spiking, SoCalGas sold gas at an average price that 

exceeded $30. SoCalGas’ ability to store gas suggests the potential for 

substantial earnings stemming from these transactions. Under a 

performance-based rates program authorized by the CPUC, a portion 

of profits derived from trading activity would have been realized by 

shareholders of SoCalGas’ parent company. For the period October 

 

32“U.S. Natural Gas Markets: Recent Trends and Prospects for the Future,” Energy 

Information Agency, May 2001, p. 14. 

33This is suggested in part by data for nationwide futures prices for natural gas. 

“Natural Gas Winter Outlook 2000–2001,” Energy Information Administration, 

Natural Gas Monthly, October 2000, p. xxiii. 34“U.S. Natural Gas Markets: Recent Trends and Prospects for the Future,” Energy 

Information Agency, May 2001, p. 23. Staff Report to the Federal Energy 

Regulatory Commission on Northwest Power Markets in November and December 

2000, February 1, 2001, pp. 21-22.

35SoCalGas, whose facilities are located solely within the state of California, is a socalled “Hinshaw” pipeline that is exempt from the Commission’s jurisdiction under 

section 1(c) of the Natural Gas Act, 15 U.S.C. 717(c) (1994). 
Chapter I 

Docket No. PA02-2-000 Price Manipulation in Western Markets I-17

2000 through March 2001, SoCalGas purchased approximately 

56,816,000 MMcf for a total of approximately $626,900,000, or 

$11.04/MMcf, and sold at wholesale 12,856,000 MMcf for 

$213,640,000, or $16.60/MMcf. These data show that SoCalGas 

benefited from higher bundled prices and general volatility during this 

period. Taken as a whole, SoCalGas’ trading activity indicates that 

profiteers included at least one market participant subject to 

California’s regulatory oversight. 

 

Staff concludes that transportation constraints and spot market 

dysfunctions contributed significantly to high spot gas prices and that 

this justifies the substitution of a new methodology for calculating 

electric prices for this period of market dysfunction that the Staff 

proposed in Chapter IV. 

Market Manipulations 

Significantly Influenced 

Reported Spot Prices for 

Natural Gas in California 

The reasons discussed thus far that impeded spot market natural gas 

prices from adhering to historical norms—supply/demand imbalance, 

inefficient market rules, and transportation constraints—may be 

attributed to the intertwining strands of poor market design, ill-timed 

market conduct, and fortuity. However, two specific activities, (1) 

trading in anomalous patterns at Topock and (2) false reporting of 

market transactions to publications for compilation in price indices, 

reflect deliberate conduct to manipulate market outcomes. These 

manipulations significantly influenced reported spot prices for natural 

gas, heaping further aggravation on the already stressed spot market. 

Because a substantial volume of spot market gas was purchased to fuel 

electric generation plants in California, the manipulations directly 

contributed to higher bids by sellers of wholesale power into the PX 

and ISO spot market and consequently to higher payments made to 

these sellers. The manipulations of anomalous trading and false 

reporting fatally undermine published price indices as reliable 

measures of market activity in a well-functioning market. 

Trading in Anomalous Patterns at Topock 

Topock is a major delivery point at the junction of El Paso Natural Gas 

Company’s interstate pipeline and Southern California Gas 

Company’s intrastate pipeline. Topock is particularly significant as a 

trading point because EOL traded gas at this point, which attracted a 

substantial volume of activity. An analysis of trading data shows that 

the activity of a single firm’s (Reliant Energy Services, Inc. (Reliant)) 
Chapter I 

Docket No. PA02-2-000 Price Manipulation in Western Markets I-18

gas trading significantly influenced spot prices at Topock. The data 

also show that Reliant benefited from exerting influence on spot 

prices. Reliant’s trading increased spot market natural gas prices on 

average by about $8.54/MMBtu in December 2000 and by about 

$1.69/MMBtu over the 9 months of the California Refund Proceeding 

absent Reliant’s churning. We explain and document this conclusion in 

the following section. 

False Reporting of Market Transactions to Publications 

Evidence continues to accumulate that natural gas trading entities 

provided false reports to periodicals that published price indices.36 The 

epidemic of false reporting affected the accuracy of spot prices, 

including the California burden prices used in the Commission’s 

California refund calculation. While widespread false reporting vitiates 

the utility of published price indices as a reliable measure of market 

activity, it has other important implications as well. First, valuation of 

forward contracts and other price-sensitive instruments is dependent in 

part on published price indices. Natural gas futures traders use 

published indices to enter contracts and assess risks. Second, spot 

prices affected by false reporting affect next-day spot prices, thus 

impacting the physical market as well. Third, false reporting 

undermines investor confidence in the ability of the physical gas 

market to operate successfully.37 We explain and document our 

conclusions regarding the extent and impact of false reporting in 

Chapter III. 

 

36For example, on December 18, 2002, the Commodity Futures Trading Commission 

(CFTC) imposed a $5 million penalty against Dynegy Marketing and Trade 

(Dynegy). “Order Instituting Proceedings Pursuant To Section 6(c) and 6(d) of the 

Commodity Exchange Act, Making Findings and Imposing Remedial Sanctions,” 

CFTC Docket No. 03-03 (December 18, 2002). In its order, the CFTC determined 

that from 2000 through June 2002, Dynegy knowingly reported false natural gas 

price and volume information to certain reporting firms in an attempt to skew gas 

indices relative to various hubs in the United States to Dynegy’s financial benefit. As 

another example, El Paso Corporation acknowledged on December 4, 2002, that 

Todd Geiger, a vice president at its El Paso Merchant Energy unit, was charged by 

Federal authorities with knowingly providing inaccurate gas price data to a trade 

publication. The false trade data were allegedly provided for transactions at Sumas, 

on the United States-Canada border. 

37Credit has largely evaporated, or become very expensive, for power trading 

companies in the wake of Enron Corporation’s collapse and disclosures elsewhere in 

the sector. In the past year, Allegheny Energy, Inc., American Electric Power, 

Progress Energy, Inc., and Williams Companies, Inc., among others, have scaled 

back their trading and Aquila, Inc., CMS Energy Corp., Dynegy, Inc., and El Paso 

Corporation, among others, have exited trading. “U.S. Utilities Retreating From 

Energy Trading,” Reuters, January 8, 2003. 
Chapter I 

Docket No. PA02-2-000 Price Manipulation in Western Markets I-19
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-1

II. Analysis of Gas Trading Activity in Southern California 

Summary 

In this chapter we conclude that Reliant Energy Services (Reliant) 

engaged in a high-volume, rapid-fire trading strategy to purchase its 

physical spot gas needs at Topock. Reliant often bought and sold many 

times its needs in quick bursts, which significantly increased the price 

of gas in that market. We describe this as “churning” and define its 

characteristics later in this chapter. We use this term even though it has 

other connotations in securities or futures trading because it gives the 

best visual image of Reliant’s behavior. Reliant’s churning enabled it to 

reduce the overall cost of the gas it actually needed. Through its 

churning, Reliant profited by selling gas at or near the top of the price 

climb it caused. Reliant was often such a large presence at Topock that 

its trading strategy moved the entire market price. Our analysis shows 

that the price of gas would have been lower by about $8.54/MMBtu in 

December 2000 and by about $1.69/MMBtu over the 9 months of the 

California Refund Proceeding absent Reliant’s churning. These inflated 

gas prices have been used in the California Refund Proceeding to set 

the prices that clear the entire electric spot market. This greatly 

magnifies the effect of Reliant’s actions upon gas prices. 

Staff concludes that these gas prices are not the result of competitive 

conditions and would not produce just and reasonable electric prices in 

the California Refund Proceeding. Later in this Report, we recommend 

alternative gas prices for the Commission’s consideration. We also 

recommend amending the Commission’s blanket certificates to 

establish guidelines for trading natural gas as well as reporting and 

monitoring requirements. 

Background 

During the winter of 2000–2001, the southern California natural gas 

market experienced high prices, large price swings, and high volumes. 

Based on findings in the Staff’s Interim Report, we made a detailed 

investigation of trading activity in the market during this period, 

focusing on trading on the EnronOnline (EOL) trading platform. We 

examined trading for all gas products traded on EOL, traded by any 

counterparty, and traded across all western locations, including both 

citygate locations as well as basins. We examined trading for spot gas, 

longer term physical gas transactions, and financial gas products. We 

found unusual trading patterns associated with Reliant transactions on 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-2

the EOL trading platform. Staff, with the assistance of Professor 

Robert S. Pindyck of MIT and Michael Quinn of Analysis 

Group/Economics, conducted an investigation into these activities.1

The results of this analysis are the subject of this chapter. 

The firms, individuals, and trading practices highlighted in this chapter 

contributed to uncertainty and price volatility in gas markets, and 

ultimately in electricity markets as well. In particular: 

♦ Analysis of trading data shows that there was often so little 

liquidity at Topock that Reliant’s gas trading significantly 

influenced spot gas prices at that location. 

♦ This in turn significantly influenced index prices, which were used 

to set the market-clearing price in the California Refund 

Proceeding. 

♦ Reliant’s trading increased spot market gas prices significantly, on 

average over $8.54 MMBtu for December 2000. 

This chapter examines natural gas trading in southern California from 

November 2000 through June 2001, focusing on Reliant’s activity on 

the EOL trading platform and on the Topock2

 location. This is a key 

point for defining published natural gas price indexes. We provide an 

in-depth descriptive analysis of Reliant’s trading activities, both in 

terms of actual trades executed and the trading staff, operations, and 

processes in place. This analysis shows that whenever the market 

exhibited anomalous patterns (e.g., high prices, price swings, high 

gross volumes traded), Reliant was typically the most active trader by 

a variety of measures. 

Our analysis also reveals that Reliant’s trading activity involved a 

great deal of churning, i.e., the repeated buying and selling of 

 

1

Robert S. Pindyck is Bank of Tokyo-Mitsubishi Professor of Economics and 

Finance at MIT’s Sloan School of Management. Professor Pindyck is a nationally 

recognized econometrician with a specialty in energy futures markets. Michael 

Quinn is a vice president with Analysis Group/Economics. He has a doctorate in 

Economics from Princeton University. Dr. Quinn specializes in the application of 

economics to issues in the natural gas and electricity industry, and he has served as 

an expert on matters involving natural gas transportation and distribution. 

2

The El Paso Natural Gas pipeline terminates at the California-Arizona border. The 

two interstate crossings from Arizona into California are at a northern corridor 

crossing between Topock, Arizona and Needles, California (where El Paso connects 

to the intrastate systems of both Southern California Gas Company and Pacific Gas 

and Electric) and at a more southern crossing between Blythe, California and 

Ehrenberg, Arizona (where El Paso connects to the intrastate system of SoCalGas). 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-3

substantial quantities of physical spot gas in a short period of time.3

Reliant’s churning generally occurred on trading days during which 

prices changed significantly—particularly in December 2000. 

We use econometric analyses to demonstrate the impact of churning 

on price levels and to estimate counterfactual prices, i.e., the prices 

that would have prevailed in the absence of Reliant’s churning 

activity. 

We also examine the relationship between Reliant’s physical trading 

and financial trading and positions on key dates to determine the 

extent to which Reliant’s financial trading activities may have 

benefited from its physical trading activities. Disaggregating and 

analyzing trading data for individual financial traders reveals that the 

trades of one particular Reliant physical trader benefited Reliant over 

$18 million from its financial positions due to its churning. 

Descriptive Analysis 

Our analysis of EOL trading activity revealed that anomalous trading 

patterns occurred under the following circumstances: 

♦ At Topock, a key pricing location for natural gas and, in turn, 

electricity in California. 

♦ For next-day gas flow, the product used for the published spot 

market index prices that affected both gas and electricity prices in 

California. 

♦ During the refund period. 

♦ In Enron’s trading with Reliant in proportions far greater than with 

other counterparties. 

♦ With the same Reliant trader. 

Most notable among these anomalies is the extent to which Reliant’s 

trading activity involved churning through the execution of a large 

number of trades in both directions (both buys and sells) in a short 

amount of time—numerous rapid buys and numerous rapid sells. The 

Reliant trader of physical spot market gas at the California-Arizona 

border, for entry into the system of Southern California Gas Company 

 

3

For the purposes of this report, “churn trading” describes a pattern of gas purchases 

and sales where: (1) a particular company both buys and sells during the trading 

interval, so that the company’s gross trading volume greatly exceeds its net trading 

volume; and (2) the company makes a relatively large number of consecutive 

purchases (or sales) in a short amount of time, often being the only buyer (or seller) 

during the burst of transactions. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-4

(SoCalGas,4 a Sempra company), would frequently buy and sell large 

quantities of gas within the (at most) 90-minute trading day, finishing 

with a net position much smaller than gross volume. The most extreme 

example is the trading activity of January 31 for flow on February 1 

(highlighted in the Initial Report). On that day, Reliant bought 

1,010,000 MMBtu of gas and sold 730,000 MMBtu, for a net purchase 

of 280,000 MMBtu. To achieve this, the Reliant trader entered into 

transactions at the rate of one every 10 seconds over the course of 30 

minutes, producing sharp price movements on EOL that all traders 

would see without knowing the cause. We did not observe any other 

firm trading in this manner—either in terms of churning buys and sells 

or rapidly executing a large number of trades. 

Figure II-1 depicts trading on Wednesday, January 31, 2001, for gas 

flow at Topock on February 1, 2001. On this day, 227 trades took 

place on EOL; more than 75 percent of them were transactions 

between Reliant and Enron. Each of the 101 blue squares in the figure 

is a purchase from Enron made by Reliant on EOL. Each of the 73 red 

crosses is a Reliant sale to Enron. The other 53 trades are between 

Enron and other counterparties. The first transaction, at 8:00 a.m., is an 

Enron purchase of 10,000 MMBtu at $11.30/MMBtu. The last 

transaction, at 9:30 a.m., is a sale of 10,000 MMBtu from Reliant to 

Enron for $15/MMBtu. The grey horizontal line is Enron’s average 

purchase price for the day, and the green line beneath it is Enron’s 

average sale price. Enron loses money for the day trading Topock spot 

gas. The dotted red line is Reliant’s average sale price to Enron, and 

the dotted blue line beneath it is Reliant’s average buy price from 

Enron. Prices rise slightly during the first hour of trading, from $11.30 

to $12. Once Reliant begins actively churning, the price rises quickly 

and steadily, peaking at $15.30 and closing $3.70 higher than the price 

at which it opened. 

 

4

Throughout this chapter, “SoCalGas” refers to the Southern California Gas 

Company and “SoCal” refers to gas at the California-Arizona border for entry into 

the system of SoCalGas. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-5

 

$11.0

$11.5

$12.0

$12.5

$13.0

$13.5

$14.0

$14.5

$15.0

$15.5

$16.0

7:50 7:59 8:08 8:16 8:25 8:34 8:43 8:52 9:01 9:10 9:18 9:27 9:36

Time

Price

Buy from Others Sell to Others Buy from Reliant Sell to Reliant

Average Buy Price from Others Average Sell Price to Others Average Buy Price from Reliant Average Sell Price to Reliant

Average Buy Price Average Sell Price

Trading patterns such as those on January 31, 2001 took place a 

number of times. From an initial review of these trading patterns, it 

appeared possible that Reliant’s trading with Enron may have 

increased prices, price volatility, and price uncertainty in the entire 

southern California gas market. That is, Reliant’s trading practices 

with Enron may have caused Enron to change the prices at which it 

was offering to buy or sell gas at any given time. In contrast, a typical 

bilateral gas trade—not taking place on EOL—would not necessarily 

affect the prices at which Enron offered to buy or sell, and thus would 

not be seen by the whole market as the new market price because the 

terms of bilateral gas transactions are generally held confidential 

between the two parties. The public nature of EOL prices is a key 

factor. 

EOL prices closely tracked the reported index prices. Figure II-2 

charts spot gas prices at the California border as traded on EOL 

(Topock and Ehrenberg) and as reported by Gas Daily. The correlation 

Figure II-1 

Day-Ahead Trades at SoCal 

January 31, 2001 for February 1, 2001 Gas 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-6

between average EOL prices and the Gas Daily midpoint price for 

SoCal was 0.999 from November 2000 through June 2001. 

0

10

20

30

40

50

60

70

11/1/2000

11/15/200011/29/200012/13/200012/27/2000

1/10/20011/24/2001

2/7/2001

2/21/2001

3/7/2001

3/21/2001

4/4/2001

4/18/2001

5/2/2001

5/16/20015/30/20016/13/20016/27/2001

Flow Date

Price

Weighted (by Volume) Average Price GasDaily SoCal Large Packages Midpoint Index

Further investigation into Reliant’s risk management, operational, and 

trading practices uncovered the following key facts: 

♦ Reliant’s primary SoCal5

 physical spot market trader worked alone 

in Los Angeles, while the rest of Reliant’s traders worked together 

in Houston. 

♦ The physical spot trading activities of this one trader were affected 

significantly by a “netting” agreement (described below) that 

provided a financial incentive to churn, and that would not have 

been meaningful had there not been “cuts” on El Paso.6

♦ For its own power plants’ needs, Reliant bought large quantities of 

gas in the spot market for many days during the refund period, 

most of it at the constrained Topock point. 

 

5

The trader dealt in gas for flow on the SoCalGas system. 6

Throughout this time period, shippers on El Paso’s system frequently did not 

receive their full nomination of capacity, but were instead cut to some lower amount. 

Among interstate pipelines, El Paso stands out in terms of the frequency of cuts. 

Figure II-2 

EOL Average Price vs. Gas Daily Midpoint Price at SoCal 

November 2000 – June 2001 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-7

♦ The pricing and load forecasting provisions in Reliant’s contract 

with the Los Angeles Department of Water and Power’s 

(LADWP’s) nomination practices, and Reliant’s risk management 

practices, all encouraged Reliant to buy spot market gas. 

Churn Trading and Netting 

Arrangement 

Reliant and others had a netting arrangement with Enron for dealing 

with SoCal trades between them. The frequent cuts of nominations 

from El Paso into SoCalGas’s system created potential problems for 

customers such as Reliant, problems that did not exist when such cuts 

did not take place. In particular, a customer selling gas might receive 

cuts in its nominations from El Paso, and such a seller might then cut 

its counterparties in order of price. This practice is sometimes referred 

to colloquially as “price majeure.” Accordingly, receiving a lower 

price on a specific transaction might bring with it a lower probability 

of flow. This concern was especially important to Reliant because it 

was such a large buyer in the spot market. 

The netting arrangement worked as follows: All of Reliant’s purchases 

from Enron were taken together to form a volume-weighted average 

price. All Reliant sales to Enron were combined in the same way. 

When there were both sales and purchases, the matching amounts were 

first netted out against each other and the balance was then settled at 

the respective average prices. Therefore, the lower-priced transactions 

were not cut disproportionately. In addition, when there were both 

sales and purchases, the offsetting or matching amounts would be 

netted against each other and settled first. Reliant could retain any net 

profit from the sales even though it was a net buyer and actually owed 

Enron money overall. 

The netting arrangement is not completely transparent. However, as 

we demonstrate later, whenever Reliant was a net buyer, the netting 

arrangement gave Reliant a financial incentive to churn. For the period 

November 2000 to June 2001, Reliant’s total profit from the netting 

agreement was $8.9 million; the majority of the profit ($7.3 million) 

came on days in which Reliant churned. 

The highest priced day in market history, December 11, 2000 for 

December 12 flow, was also the day of the highest profits from 

netting. Reliant lost money from netting on only 3 of the 24 churn 

days, and the total amount of losses was less than $30,000. In contrast, 

the netting arrangement resulted in a number of days of significant 

upside for Reliant. Reliant’s profits from netting were approximately 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-8

$5 million for December. Virtually all of these profits were in the first 

8 days of trading, when market prices rose to all-time highs. 

Econometric Analysis 

An econometric analysis of the effect of Reliant’s trading on market 

prices showed the following: 

♦ A clear, robust, and statistically significant relationship—

controlling for other factors—between Reliant’s churning and 

prices rising. 

♦ The price rise generally persisted for a few days before ultimately 

dissipating. 

♦ Gas prices in southern California were, on average, more than 

$8.54 MMBtu/d higher in December 2000 than they would have 

been absent Reliant’s EOL trading activity. 

Reliant was a large and consistent spot gas buyer for both its own 

needs and those of LADWP. In this regard, Reliant was unlike most of 

the other firms buying and selling gas for the SoCal area. Reliant’s 

frequent need for large amounts of spot gas, and its lack of storage, 

may have affected its approach to trading, as Reliant was at risk for the 

market discovering that Reliant needed a lot of gas on a particular day. 

Staff struggled with whether Reliant’s trading activities were affected 

by the level of transparency on EOL, whether some of Reliant’s 

behavior could have been attributed to price discovery, and that 

Reliant may have been merely “riding the market” and simply 

profiting from that ride. Such an explanation, however, would have us 

overlook the enormous share of trading Reliant comprised on many 

days, the rapid-fire manner in which Reliant frequently bought gas, 

and the resultant price increases. The volumes and trading pattern 

simply do not lend themselves to testing the waters for price discovery. 

Nonetheless, it is possible that prices would have risen by some 

amount on at least some of the days when Reliant churned, even if it 

had not churned. 

Our econometric analysis clearly establishes a correlation between 

Reliant’s churn trading and higher gas prices. What it does not do—

and cannot do by itself—is prove causation. In addressing causation, 

Staff took into account all of the available information, of which the 

econometric analysis is but one component. The fact that no other 

company remotely approached Reliant’s size, Reliant’s trading 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-9

strategy, and the markedly different market behavior on days when 

Reliant did not churn are all important considerations. When viewed in 

total, the evidence supports a conclusion that churning caused prices to 

rise. 

Linkages Between Physical 

and Financial Trading 

The investigation for linkages between Reliant’s physical and financial 

trading indicated: 

♦ Reliant was an active trader of financial gas derivative products in 

southern California, trading SoCal basis swaps and SoCal balanceof-month “swing” swaps throughout the refund period.7

♦ One Reliant financial trader made profits of $23.4 million from 

December SoCal swaps purchased on November 30, 2000. After 

this transaction, Reliant’s trader of physical spot market gas at the 

same location then churned for 8 consecutive trading days. 

♦ About $18 million of the profits from these financial trades 

resulted from Reliant’s churning. 

Investigation of Reliant 

Trading 

The Initial Report8 stated that certain gas trading patterns on EOL 

would be investigated further because a preliminary examination of 

physical spot gas transactions on EOL identified anomalous trading 

patterns, in particular with respect to Reliant’s trading with Enron.9

While it would be imprecise to describe any individual day during this 

time period as “typical,” we present a few summary statistics on 

average EOL trading levels for SoCal (Topock/Ehrenberg) during the 

 

7

In a gas “swap,” two counterparties execute a trade in which the buyer pays a fixed, 

known price for some notional quantity of gas and the seller pays a price that will 

vary with the market price, which will only be known later. Thus, the buyer in a 

swap transaction is going long and is betting that prices will rise. The seller is betting 

that prices will fall. These transactions are settled financially, involving no gas 

delivery. The two types of swaps that we examined are explained below. 8

Initial Report on Company-Specific Separate Proceedings and Generic 

Reevaluations; Published Natural Gas Price Data; and Enron Trading Strategies: 

Fact Finding Investigation of Potential Manipulation of Electric and Natural Gas 

Prices, Docket No. PA02-2-000, prepared by the Staff of the Federal Energy 

Regulatory Commission, August 2002, pp. 49-51. 

9

The Initial Report did not name Reliant, but referred to it as an unidentified “single 

counterparty.” 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-10

period from November 2000 to June 2001. On average, 78 SoCal spot 

trades per day took place. Of these, 27 were with Reliant and 51 were 

with all other firms combined. On average, Reliant bought (net) 

144,000 MMBtu/d from Enron during this time period, while all other 

counterparties combined to sell (net) Enron 250,000 MMBtu/d. The 

combined gross trading of counterparties other than Reliant exceeded 

their net by 70,000 MMBtu/d. Reliant’s gross trading exceeded its net 

trading by more than 100,000 MMBtu/d. 

Examples of anomalous trading patterns include: 

♦ On dozens of occasions, these 2 counterparties traded with each 

other more than 20 times (up to 174 times) within the (at most) 90-

minute trading day. No other firm traded with Enron in this way, 

either in terms of number of trades or the rate at which transactions 

would take place. Appendix II-A provides a number of tables, as 

described below, highlighting Reliant’s trading activity on EOL. 

♦ Reliant was by far the firm most likely to engage in consecutive 

trades for spot contracts on the EOL system. During one timeframe 

on January 31, 2001, Reliant made 43 consecutive trades before 

another firm conducted a trade. Reliant was the only firm to make 

more than 13 consecutive trades and was the counterparty for 34 of 

the 40 longest streaks of consecutive trades. 

♦ Reliant initiated transactions with Enron in bursts unmatched by 

other counterparties. From November 1, 2000 through June 2001, 

only once did another firm conduct as many as 10 trades at a single 

location within a “clock minute” (e.g., 8:51:00 a.m. to 8:51:59 

a.m.); Reliant did this 14 times, and was the top trader for 38 of the 

40 busiest minutes. 

♦ Spot market trading for next-day flow from El Paso Natural Gas 

into SoCalGas at Topock, Arizona, showed unusual activity 

between Enron and Reliant. As the Initial Report indicated:10 

(1) Topock spot market prices are of particular interest because of 

their impact on actual prices paid for gas and electricity and 

(2) EOL prices closely tracked reported index prices. 

Staff found these patterns troubling because it appeared that Reliant’s 

trading with Enron may have increased prices, price volatility, and 

price uncertainty to the entire southern California gas market. The 

market would see the effects of the transactions’ pricing through a 

change in the prices at which Enron would offer to buy and sell gas 

without knowing that only one trader was causing the change. In 

contrast, a typical bilateral gas trade—not taking place on EOL—

would not be seen by the whole market as the new market price, since 

 

10Initial Report, pp. 52-55. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-11

the terms of bilateral gas transactions are generally held confidential 

between the two parties. The public nature of EOL prices is a key 

factor. 

Accordingly, we analyzed in detail: 

1. EOL trading activity of gas for delivery into the SoCalGas system, 

both for physical gas and for financially settled gas derivative 

transactions that were based on SoCal prices (swaps and basis 

swaps). 

2. Trading activity between Enron and Reliant for Topock spot 

market gas and for all other western transactions, both physical and 

financial. 

3. Trading activity of the individual traders involved in the 

anomalous trades. 

4. Trading activity of Reliant with all counterparties. 

Exploratory Descriptive Analysis 

Preliminary analyses examined EOL trading records for 2000 and 

2001.11 Staff subsequently narrowed the focus to the period November 

2000 to June 2001 for specific analyses (described below). These 

analyses revealed the unique characteristics of spot trading in southern 

California and Reliant’s trading in particular. The following was 

determined: the “products” that were most actively traded, the types of 

prices at which the transactions took place, and the geographic 

locations where trading was the most active. 

By and large, spot gas was the most heavily traded product across all 

locations. On EOL, spot gas transactions took place at fixed (rather 

than indexed) prices, and are the types of transactions that allegedly 

are used for producing the reported daily spot market index prices 

published by Gas Daily, Natural Gas Intelligence (NGI), and Inside 

FERC. These daily spot market index prices are used in physical gas 

contracts tied to indexes and for settling many financial derivative 

products, such as balance-of-month swing swaps (defined and 

discussed further below). 

Among the various geographic locations, the California-Arizona 

border for entry into the SoCalGas system was the most actively 

traded. On EOL, of the entry points into SoCalGas, Enron offered only 

Topock until March 2001, when it added Ehrenberg. Another 750,000 

 

11The EOL data we have comprise all physical and financial trades transacted on 

EOL for the period February 7, 2000 through June 29, 2001 for the western part of 

the United States. Data for January 2000 are incomplete. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-12

MMBtu/d could enter the SoCalGas system at the terminus of the 

Transwestern pipeline (at Needles, California). Within California, gas 

was also traded at Hector Road (the interconnection of Mojave, 

SoCalGas, and PG&E) and Wheeler Ridge (the interconnection of 

Kern River and SoCalGas). However, none of these locations were 

traded on EOL. 

The fact that Enron traded only at Topock during December 2000, for 

example, meant that someone who wanted to buy gas on EOL and 

deliver it into the SoCalGas system was limited to the constrained 

Topock location. Only 540,000 MMBtu/d could enter the SoCalGas 

system at Topock.12 Another 1,210,000 MMBtu/d could enter at 

Ehrenberg and Needles. Accordingly, restricting one’s trading to 

Topock could have been a significant limitation. 

Figure II-3 

 

12Throughout this chapter, volumetric measures of gas pipeline capacity are reported 

in terms of MMBtus, using an approximation of 1 MMBtu = 1 Mcf. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-13

The bulk of our EOL trading analysis focuses on spot gas traded at the 

California-Arizona border. Spot market, or swing, gas is typically 

traded 1 day ahead of its flow date.13 For weekends and holidays, gas 

on EOL was traded in a multiday package—e.g., on Friday a buyer 

purchases gas for flow on each of Saturday, Sunday, and Monday. 

Reliant’s SoCalGas Trading on EnronOnline Stands Out 

Looking across all western locations where spot market gas was traded 

on EOL, the volume of gas traded by Reliant with Enron, at Topock in 

particular, is quite prominent. 

Table II-1 covers the period November 1, 2000 through June 2001 and 

sums the volume of western physical spot market trading activity for 

the top 15 Enron counterparties on EOL. As the table shows, Reliant 

had the largest gross trading volumes for all locations combined, and 

Reliant’s Topock volumes alone are more than the second largest 

counterparty’s (Duke) combined EOL activity across all locations. In 

the EOL data, Topock was also the most active location for El Paso, 

Dynegy, Aquila, and Williams, in addition to Reliant. 

Reliant’s head of gas trading explained that Reliant had a risk 

management policy of buying forward gas to match forward power 

contracts and relying strictly on spot gas for spot electric sales. 

Because it was almost entirely in the spot electric market, Reliant 

relied heavily on spot gas. 

 

13Monthly (or longer term) “baseload” gas is a different product. Baseload gas prices 

are set based on trading in the last week of the month prior to the month of gas flow. 

For example, “March gas” is priced based on trades during the last week of 

February. A quantity of March gas, such as 10,000 MMBtu/d, involves the delivery 

of 10,000 MMBtu each day from seller to buyer. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-14

Table II-1 

Top 15 Counterparties by Gross Volume 

Top Locations by Gross Volume 

(EOL, November 1, 2000 - June 30, 2001) 

 

Top 15 Counterparties Top Locations 

Counterparty 

Number of 

Transactions in All 

Locations 

Gross 

Volume Location 

Number of 

Transactions in 

Location 

Gross 

Volume in 

Location 

Reliant Energy Services, Inc. 4,870 64,395,219 SoCal Topock 

EPNG 

3,412 48,103,388 

Duke Energy Trading and Marketing, 

L.L.C. 

3,406 37,245,838 PG&E Ctygte 

Pool 

1,491 16,171,475 

El Paso Merchant Energy, L.P. 2,847 29,679,471 SoCal Topock 

EPNG 

668 8,910,324 

Dynegy Marketing and Trade 2,459 25,053,591 SoCal Topock 

EPNG 

695 9,534,971 

Aquila Energy Marketing Corporation 2,224 22,983,237 SoCal Topock 

EPNG 

585 7,959,234 

Enserco Energy, Inc. 2,819 20,787,593 Opal 978 6,965,285 

Cook Inlet Energy Supply L.L.C. 2,370 19,991,233 Opal 1,318 10,113,500 

BP Energy Company 1,993 16,841,184 Opal 700 5,096,092 

Coral Energy Resources, L.P. 1,816 16,548,171 PGT Malin 494 4,461,224 

Mirant Americas Energy Marketing, L.P. 1,509 14,103,077 PG&E Ctygte 

Pool 

464 4,654,951 

Sempra Energy Trading Corp. 1,288 11,957,743 EPNG SoCal 

Ehrenberg 

250 3,102,500 

Calpine Energy Services, L.P. 988 9,113,794 PG&E Ctygte 

Pool 

736 6,579,128 

AEP Energy Services, Inc. 880 8,398,119 PG&E Ctygte 

Pool 

291 2,469,500 

Williams Energy Marketing & Trading 

Company 

659 6,749,032 SoCal Topock 

EPNG 

242 3,286,000 

Enron Energy Services, Inc. 795 6,698,508 PG&E Ctygte 

Pool 

394 3,373,500 

Note: 

All transactions represent summaries of spot purchases, unless otherwise noted. 

All volume traded includes weekends and holidays, unless otherwise noted. 

Reliant was also highly active in western gas trading on EOL from a 

variety of perspectives: 

♦ From November 1, 2000 through June 2001, Reliant had the 19 

busiest days by trading volume (both buys and sells), and 30 of the 

40 busiest days. On each of its busiest 3 days, it traded contracts 

for more than 1,800,000 MMBtu in volume, more than twice the 

busiest day of any other party. (See Appendix II-A, Table II-A1.) 

♦ Reliant also had the 8 largest net purchase days in EOL spot 

trading for western gas from November 1, 2000 through June 

2001, 9 of the 10 busiest days, and 32 of the 40 busiest days. (See 

Appendix II-A, Table II-A2.) 

♦ Unlike Reliant’s dominance on the purchasing side, several firms 

appear on the list of sellers with the largest net sales days (by net 

sales volume) in trading of western spot gas on the EOL system 

from November 1, 2000 through June 2001. (See Appendix II-A, 

Tables II-A3 and II-A4.) Five firms—SoCalGas (Sempra), El 

Paso, Dynegy, Duke, and Aquila—appear among the 10 biggest 

sellers. SoCalGas sold 600,000 MMBtu on November 22, 2000, 

the biggest single day of net sales. Note that this was the day 

Table II-1. Top 15 Counterparties by Gross Volume and Top Locations 

by Gross Volume (EOL, November 1, 2000 – June 30, 2001) 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-15

before Thanksgiving, so spot contracts sold on this day were for 5 

days; SoCalGas’s sales of 600,000 MMBtu represent 120,000 

MMBtu/d. 

♦ Reliant purchased more than 6,000,000 MMBtu each month on the 

spot market from December 2000 through February 2001. These 

monthly volumes were more than twice the size of the next largest 

monthly purchases by any other firm. Reliant was the top buyer for 

4 of the 5 busiest months for net purchases. (See Appendix II-A, 

Table II-A5.) 

♦ From November 1, 2000 through June 2001, Reliant had all of the 

30 busiest trading days, defined by number of EOL trades executed 

for spot gas at Topock or Ehrenberg. The busiest day for a nonReliant counterparty was March 23, 2001, when El Paso Merchant 

had 34 trades, the 40th busiest day. (See Appendix II-A, Table IIA6.) 

Reliant’s Purchases at Topock 

From November 1, 2000 through June 2001, both Enron and Reliant 

frequently made net purchases using spot contracts on EOL that were 

large relative to the SoCalGas takeaway capacity (540,000 MMBtu/d) 

at that point. Contrary to statements sometimes made about Enron in 

general and Enron’s EOL trading platform in particular, Enron did not 

simply act as a middleman matching buyers and sellers on EOL. Quite 

often, Enron would end a trading day with a substantial net physical 

purchase and, on some other days, a net sale. 

On 39 different occasions, Enron or Reliant purchased more than 

270,000 MMBtu/d at Topock (see Table II-2), representing more than 

half of the pipeline’s takeaway capacity at that point. Enron purchased 

more than 270,000 MMBtu/d on 10 days and Reliant did so on 30 

days. On December 12, 2000, both firms purchased more than 270,000 

MMBtu/d. The combined purchases of Enron and Reliant exceeded 

270,000 MMBtu/d on 29 days. These purchases are listed (in bold) 

among the 39 shown in Table II-2 below. 

Regarding what constitutes a large physical purchase in the spot 

market, Reliant’s head of gas trading stated, “Buying 200,000 for nextday gas is also a big amount for next-day gas.”14 Essentially, on quite a 

number of days, Reliant (and Enron, to a lesser extent) swamped the 

market point. 

On 2 days during the period, each firm purchased more than 540,000 

MMBtu/d, the total SoCalGas takeaway capacity. On these days, 

 

14Interview with FERC Staff, September 2002. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-16

Reliant’s net purchases alone ensured that there would be cuts. 

Moreover, on 10 days the combined purchases exceeded the total 

SoCalGas takeaway capacity. Although, along with other customers, 

Reliant faced cuts in its nominations at Topock, at the same time 

Reliant was a substantial contributor to the situation there. 

Table II-2. EOL Trading Activity in Topock Spot Gas, Days on Which Enron or 

Reliant Purchased More Than 270,000 MMBtu/d, November 2000 – June 2001 

Transaction 

Date 

Net Enron 

Purchases 

(MMBtu/day) 

Net Reliant 

Purchases 

(MMBtu/day) 

Combined 

Purchases 

(MMBtu/day) 

 (1) (2) (3) = (1) + (2) 

11/2/00 290,000 -45,000 245,000 

11/3/00 345,000 -45,000 300,000 

11/14/00 340,000 -45,000 295,000 

11/27/00 195,000 470,000 665,000 

11/28/00 630,000 -45,000 585,000 

11/29/00 555,000 130,000 685,000 

12/5/00 185,000 289,000 474,000 

12/6/00 345,000 177,000 522,000 

12/12/00 282,000 410,000 692,000 

12/13/00 170,000 557,000 727,000 

12/14/00 230,454 322,000 552,454 

12/15/00 225,000 452,000 677,000 

12/18/00 175,000 460,000 635,000 

12/19/00 265,000 270,000 535,000 

12/20/00 165,000 380,000 545,000 

12/21/00 348,000 215,000 563,000 

1/2/01 -80,050 340,000 259,950 

1/3/01 -97,500 570,000 472,500 

1/4/01 10,000 310,000 320,000 

1/5/01 -40,000 340,000 300,000 

1/10/01 -35,000 270,000 235,000 

1/16/01 -40,000 445,000 405,000 

1/17/01 45,000 280,000 325,000 

1/22/01 -25,000 380,000 355,000 

1/24/01 -15,000 290,000 275,000 

1/29/01 321,650 -70,000 251,650 

1/31/01 -40,000 280,000 240,000 

2/1/01 -80,000 370,000 290,000 

2/2/01 -66,000 355,000 289,000 

2/7/01 25,000 280,000 305,000 

2/12/01 -70,000 410,000 340,000 

2/13/01 -97,500 370,000 272,500 

2/14/01 -150,000 410,000 260,000 

2/15/01 -157,500 330,000 172,500 

2/16/01 -100,000 345,000 245,000 

2/20/01 -90,000 325,000 235,000 

2/21/01 -75,000 305,000 230,000 

2/22/01 67,500 390,000 322,500 

4/26/01 364,512 -10,000 354,512 

Note: Daily totals shown in bold indicate net purchases of more than 270,000 MMBtu/d, 

representing more than half of the pipeline’s capacity. Daily totals shown in bold and 

boxed indicate net purchases of more than 540,000 MMBtu/d, representing more than the 

pipeline’s total capacity. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-17

Reliant-Enron Churn Trades Sometimes Dominated a Day’s Trading 

On particularly active days of Reliant SoCal trading, trades between 

Reliant and Enron sometimes comprised the majority of the day’s 

SoCal trading on EOL. Our subsequent analysis has determined that 

from November 1, 2000 through June 2001, there were 24 days on 

which Reliant both bought 100,000 MMBtu/d and sold 100,000 

MMBtu/d (referred to as a “churn” day in this chapter) for next-day 

gas at the California-Arizona border. On the days when this took 

place, Reliant tended to buy and sell gas in rapid-fire succession. In 

many cases, this behavior had pronounced effects on prices. This 

churning by Reliant is something we did not observe for other firms.15

In Figures II-4 to II-6, we provide representative examples of 3 days of 

Reliant churning in 2001: January 31, February 2, and June 11. 

Figure II-4 depicts trading on Wednesday, January 31, 200116 for gas 

flow at Topock on February 1, 2001. On this day, 227 trades took 

place (2,240,000 MMBtu); more than 75 percent were transactions 

between Reliant and Enron. Each of the 101 blue squares in the figure 

is a purchase from Enron made by Reliant on EOL. Each of the 73 red 

crosses is a Reliant sale to Enron. The other 53 trades are between 

Enron and other counterparties (black crosses are Enron purchases 

from parties other than Reliant and purple squares are Enron sales to 

parties other than Reliant). The first transaction, at 8:00 a.m., is an 

Enron purchase of 10,000 MMBtu at $11.30/MMBtu (from El Paso). 

The last transaction, at 9:30 a.m., is a sale of 10,000 MMBtu from 

Reliant to Enron for $15/MMBtu. The grey horizontal line is Enron’s 

average purchase price for the day, and the green line beneath it is 

Enron’s average sale price. Enron loses money for the day trading 

Topock spot gas. The dotted red line is Reliant’s average sale price to 

Enron, and the dotted blue line beneath it is Reliant’s average buy 

price from Enron. For the first hour of trading, prices rise slightly, 

from $11.30 to $12. Once Reliant begins actively churning, the price 

rises quickly and steadily, peaking at $15.30 (Duke buying from 

Enron) and closing $3.70 higher than the price at which it opened. 

 

15We define churning as days on which Reliant both purchased and sold at least 

100,000 MMBtu. It was often the case that Reliant both bought and sold far more 

than 100,000 MMBtu. 

16Most of the date references are to transaction dates, which typically take place 1 

day before gas flow. For weekends and holidays, a transaction date may involve 

trading of a multiday packet of gas. For example, on Friday, December 8, 2000, a 

purchase of 10,000 MMBtu of gas on EOL was for flow on each day of December 9 

to 11. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-18

In total, Reliant bought 1,010,000 MMBtu of gas and sold 730,000 

MMBtu, for a net purchase of 280,000 MMBtu. To achieve this, the 

Reliant trader entered into transactions at the rate of one every 10 

seconds over the course of 30 minutes, producing sharp price 

movements on EOL that all traders would see without knowing the 

cause. We did not observe any other firm trading in this manner—

either in terms of churning buys and sells or rapidly executing a large 

number of trades. 

 

$11.0

$11.5

$12.0

$12.5

$13.0

$13.5

$14.0

$14.5

$15.0

$15.5

$16.0

7:50 7:59 8:08 8:16 8:25 8:34 8:43 8:52 9:01 9:10 9:18 9:27 9:36

Time

Price

Buy from Others Sell to Others Buy from Reliant Sell to Reliant

Average Buy Price from Others Average Sell Price to Others Average Buy Price from Reliant Average Sell Price to Reliant

Average Buy Price Average Sell Price

Figure II-5 depicts another Reliant churn day, February 2 for flow on 

February 3, 4, and 5. Again, we observe a pattern of Reliant buying 

and selling in extended bursts. In total, Reliant transacted 1,235,000 

MMBtu of gas, for a net purchase of 355,000 MMBtu. Prices on this 

day began at $14/MMBtu (Mirant selling to Enron) and reached a peak 

of $18.10/MMBtu (Reliant buying from Enron) before closing at 

$15.75/MMBtu (Reliant buying from Enron). Trading lasted 70 

minutes. The Gas Daily price for the day was $15.39/MMBtu. For the 

day, Enron’s buy price was below its sell price, so in that sense Enron 

Figure II-4 

Day-Ahead Trades at SoCal 

January 31, 2001 for February 1, 2001 Gas
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-19

came out slightly ahead. Once again, Reliant’s average sell price to 

Enron was above its buy price. 

Figure II-5 

Day-Ahead Trades at SoCal 

February 2, 2001 for February 5, 2001 Gas 

$13.0

$13.5

$14.0

$14.5

$15.0

$15.5

$16.0

$16.5

$17.0

$17.5

$18.0

$18.5

$19.0

7:55 8:09 8:24 8:38 8:52 9:07 9:21

Time

Price

Buy from Others Sell to Others Buy from Reliant Sell to Reliant

Average Buy Price from Others Average Sell Price to Others Average Buy Price from Reliant Average Sell Price to Reliant

Average Buy Price Average Sell Price

In Figure II-6, we see a somewhat different trading pattern. Here, 

Reliant does the bulk of its purchasing—400,000 MMBtu in 10,000-

MMBtu increments—in a 5-minute time span and then sells off 

224,000 MMBtu over the remainder of the trading interval, much of 

that in the last minute of trading. On this day, Enron’s buy price is 

above its sell price. Reliant sells at a higher average price than it pays. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-20

Figure II-6 

Day-Ahead Trades at SoCal 

June 11, 2001 for June 12, 2001 Gas 

$4.5

$5.0

$5.5

$6.0

$6.5

$7.0

$7.5

$8.0

7:40 7:55 8:09 8:24 8:38 8:52 9:07 9:21 9:36

Time

Price

Buy from Other Sell to Others Buy from Reliant Sell to Reliant

Average Buy Price from Others Average Sell Price to Others Average Buy Price from Reliant Average Sell Price to Reliant

Average Buy Price Average Sell Price

Reliant Trading and Market Volatility 

Although Reliant was often a major factor in the SoCal points traded 

on EOL, there were days when Reliant’s activity was fairly minimal. 

On those days, there were typically less pronounced price movements. 

Figures II-7 to II-9 depict three examples of days on which SoCal spot 

trading on EOL was fairly active but Reliant’s churning did not play a 

part—November 28, 2000, January 29, 2001, and June 7, 2001. 

What is most notable about these days is what is not observed—we do 

not see the rapid price swings up and down that are observed when 

Reliant churns. There are no bursts of trades at all, and prices remain 

flat for much of the day. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-21

Figure II-7 

Day-Ahead Trades at SoCal 

 November 28, 2000 for November 29, 2000 Gas 

$13.0

$13.5

$14.0

$14.5

$15.0

$15.5

$16.0

$16.5

$17.0

7:50 7:57 8:04 8:12 8:19 8:26 8:33 8:40 8:48 8:55 9:02 9:09 9:16 9:24 9:31 9:38

Time

Price

Buy from Others Sell to Others Buy from Reliant Sell to Reliant

Average Buy Price from Others Average Sell Price to Others Average Buy Price from Reliant Average Sell Price to Reliant

Average Buy Price Average Sell Price

Figure II-8 

Day-Ahead Trades at SoCal 

 January 29, 2001 for January 30, 2001 Gas 

$13.0

$13.5

$14.0

$14.5

$15.0

7:50 7:59 8:08 8:16 8:25 8:34 8:43 8:52 9:01 9:10 9:18 9:27 9:36

Time

Price

Buy from Others Sell to Others Buy from Reliant Sell to Reliant

Average Buy Price from Others Average Sell Price to Others Average Buy Price from Reliant Average Sell Price to Reliant

Average Buy Price Average Sell Price
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-22

Figure II-9 

Day-Ahead Trades at SoCal 

 June 7, 2001 for June 8, 2001 Gas 

$5.0

$5.5

$6.0

$6.5

7:50 7:57 8:04 8:12 8:19 8:26 8:33 8:40 8:48 8:55 9:02 9:09 9:16 9:24 9:31 9:38

Time

Price

Buy from Other Sell to Others Buy from Reliant Sell to Reliant

Average Buy Price from Others Average Sell Price to Others Average Buy Price from Reliant Average Sell Price to Reliant

Average Buy Price Average Sell Price

Figures II-7 to II-9 chart 3 relatively busy days at Topock on which 

Reliant was not a major force. The trading patterns observed on these 

days are visually quite different from those days on which Reliant was 

a major presence. No counterparty is seen to make bursts of purchases 

(or sales) in the way Reliant did. Trading activity is less frequent and 

price movements are less pronounced. Even when a number of trades 

in the same direction take place, such as on January 29, when 

counterparties sell to Enron repeatedly without an intervening 

purchase, we do not observe price movements of the sort that take 

place when Reliant rapidly enters into numerous transactions. 

As a market point, the Topock point looks markedly different on the 

days of low Reliant activity. We also note that, rather than observing a 

balanced mix of both buyers and sellers transacting with Enron, what 

we see is tilted strongly toward counterparties selling gas to Enron. 

Enron was frequently a net buyer of spot gas at Topock. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-23

Reliant Did Most of the Churning 

After observing Reliant’s churn trading, we performed an additional 

analysis to determine whether churn trading was found among 

counterparties other than Reliant or at other locations. As noted above, 

we defined churning as when a firm both bought and sold at least 

100,000 MMBtu/d of spot gas on the same day for delivery at the same 

location. For the period from February 2000 through June 2001, we 

found 26 such instances. It was primarily Reliant that did this type of 

trading for all locations and counterparties; Reliant has 24 of the 26 

churns (all at SoCal). (See Appendix II-A, Table II-A7.) While Reliant 

did not churn every day, it churned over the entire 8-month period and 

did so profitably, earning approximately $9 million from this trading 

strategy (see Table II-7 below). 

Reliant’s Churning 

In this section we focus on Reliant’s churn trading. We examine the 

days on which churning took place and the Gas Daily index and EOL 

prices on those days. We look at when churning was most prevalent, 

who within Reliant carried out the trades, and what this trading 

behavior may have looked like to the rest of the market at the time. 

Reliant’s Churn Days 

Although our data sample begins in February 2000, Reliant’s churning 

takes place from November 1, 2000 through June 2001. In Table II-3 

below, we list each of the 24 days of Reliant’s churning on EOL. On 

many days, Reliant’s trading volumes were much higher than our 

definition of at least 100,000 MMBtu/d bought and sold. For example, 

on December 5, 2000, Enron’s total trading volume for Topock was 

1,465,000 MMBtu. Of this, 62 percent (911,000 MMBtu) was 

transacted with Reliant and 554,000 MMBtu was transacted with all 

other counterparties combined. Reliant’s net purchase from Enron for 

the day was 289,000 MMBtu. Other counterparties sold 474,000 

MMBtu (net) to Enron. So for the day, Reliant traded 622,000 more 

MMBtu gross (311,000 MMBtu bought and 311,000 MMBtu sold) 

than it bought net. On the following day, Reliant’s trading comprised 

60 percent of the day’s trading volume. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-24

Table II-3. Reliant Churn Days at SoCal (Topock and Ehrenberg), 

Summary of Physical Daily Trades of Reliant and All Other Counterparties 

Transaction 

Date 

Contracted Flow 

Date or Flow 

Period 

EOL Gross 

Volume 

(MMBtu/d) 

Reliant Gross 

Volume 

(MMBtu/d) 

Reliant 

Net 

Volume 

(MMBtu/d)

Reliant 

Share of 

EOL 

Trading 

Volume 

Reliant 

Churn 

Volume 

Reliant 

Churn 

Volume 

Share of 

Trading 

11/1/00 11/2/00 820,000 200,000 0 24.4% 200,000 100.0% 

11/13/00 11/14/00 1,095,000 390,000 10,000 35.6% 380,000 97.4% 

11/30/00 12/1/00 924,000 502,000 138,000 54.3% 364,000 72.5% 

12/1/00 12/2 – 12/4/00 1,212,000 760,000 260,000 62.7% 500,000 65.8% 

12/4/00 12/5/00 985,000 513,000 107,000 52.1% 406,000 79.1% 

12/5/00 12/6/00 1,465,000 911,000 289,000 62.2% 622,000 68.3% 

12/6/00 12/7/00 1,345,000 803,000 177,000 59.7% 626,000 78.0% 

12/7/00 12/8/00 1,201,000 700,000 260,000 58.3% 440,000 62.9% 

12/8/00 12/9 – 12/11/00 975,500 480,000 180,000 49.2% 300,000 62.5% 

12/11/00 12/12/00 1,892,000 1,354,000 246,000 71.6% 1,108,000 81.8% 

12/13/00 12/14/00 1,510,000 773,000 557,000 51.2% 216,000 27.9% 

12/19/00 12/20/00 1,235,000 670,000 270,000 54.3% 400,000 59.7% 

1/31/01 2/1/01 2,240,000 1,740,000 280,000 77.7% 1,460,000 83.9% 

2/2/01 2/3 – 2/5/01 1,604,000 1,235,000 355,000 77.0% 880,000 71.3% 

2/13/01 2/14/01 1,042,500 710,000 370,000 68.1% 340,000 47.9% 

2/28/01 3/1/01 812,000 330,000 90,000 40.6% 240,000 72.7% 

3/1/01 3/2/01 570,000 315,000 5,000 55.3% 310,000 98.4% 

3/2/01 3/3 – 3/5/01 790,000 405,000 165,000 51.3% 240,000 59.3% 

3/20/01 3/21/01 610,000 270,000 50,000 44.3% 220,000 81.5% 

3/22/01 3/22/01 570,000 230,000 -30,000 40.4% 200,000 87.0% 

3/23/01 3/24 – 3/26/01 1,105,000 670,000 30,000 60.6% 640,000 95.5% 

4/3/01 4/4/01 538,012 220,000 -20,000 40.9% 200,000 90.9% 

6/11/01 6/12/01 1,179,000 624,000 176,000 52.9% 448,000 71.8% 

6/13/01 6/14/01 1,023,000 489,479 269,479 47.8% 220,000 44.9% 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-25

Reliant’s Churning Peaked in December 2000 

Of the 24 churn days shown in Table II-3, 8 are on consecutive trading 

days for delivery in December 2000. These particular days encompass 

the highest ever gas prices in California, reaching their peak on the 

eighth consecutive day of churning. The table shows that Reliant 

churning comprises more than 70 percent of its gross trading volume. 

Figure II-10 charts price activity during December 2000, noting which 

days were churn days. The figure demonstrates that prices rose on 

most churn days. On the day after this string of churning ends, prices 

fall by more than $25/MMBtu. The price data are provided in 

Appendix II-A, Table II-A8. 

Figure II-10 

December Price Chart 

0

10

20

30

40

50

60

70

80

11/30/2000

12/2/200012/4/200012/6/200012/8/2000

12/10/200012/12/200012/14/200012/16/200012/18/200012/20/200012/22/200012/24/200012/26/200012/28/200012/30/2000

Flow Date

Price

EOL High

EOL Low

EOL Closing Price

Weighted (by Volume) Average Price

Days for Which Gas Flow Was Traded on a Churn Day
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-26

Reliant Bought and Sold in Bursts 

All transactions on EOL are initiated by the counterparty, not by 

Enron. Enron would constantly offer two prices—one at which it was 

willing to buy and a higher one at which it was willing to sell. It was 

up to counterparties, such as Reliant, to make the decision to transact. 

Enron could change its posted prices to encourage trading (e.g., by 

lowering the price at which it was offering to sell, a counterparty 

would be more likely to buy), but it could not initiate transactions. 

Reliant initiated transactions with Enron in bursts unmatched by other 

counterparties: 

♦ From November 1, 2000 through June 2001, only once did another 

firm conduct as many as 10 trades at a single location within a 

clock minute (e.g., 8:51:00 a.m. to 8:51:59 a.m.); Reliant did this 

14 times. Reliant was the trader for 38 of the 40 busiest minutes. 

(See Appendix II-A, Table II-A9.) 

♦ When the time interval is increased from 1 clock minute to 5 clock 

minutes (e.g., 8:41:00 through 8:45:59), Reliant’s trading pattern is 

even more unusual. No other firm ever made 15 or more trades in a 

single location within 5 minutes; Reliant did this 36 times. Reliant 

was the trading party for 39 of the 40 busiest 5-minute intervals. 

(See Appendix II-A, Table II-A10.) 

♦ When observed somewhat differently, Reliant was by far the firm 

most likely to engage in consecutive trades for spot contracts on 

the EOL system. During one time span on January 31, 2001, 

Reliant made 43 consecutive trades before another firm conducted 

a trade. Reliant was the only firm to make more than 13 

consecutive trades and was the counterparty for 34 of the 40 

longest such streaks. (See Appendix II-A, Table II-A11.) 

♦ In addition to being far more likely to engage in long stretches of 

consecutive trades, Reliant was also the most likely firm to transact 

a series of consecutive buys or sells without trading by any other 

firm. Reliant had the 4 longest streaks of consecutive purchases 

from Enron, as well as 8 of the 10 longest and 36 of the 40 longest 

streaks of consecutive purchases from Enron. (See Appendix II-A, 

Table II-A12.) 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-27

♦ In addition to long sequences of buy transactions and even though 

Reliant was usually a net buyer, Reliant also engaged in long 

sequences of sell transactions, although not generally as long as the 

buy sequences. Reliant transacted 6 of the 10 and 22 of the 40 

longest streaks of consecutive sells to Enron (i.e., Enron buys). 

(See Appendix II-A, Table II-A13.) 

Example of Effect of Burst Trading: December 11, 2000 

Four of the forty longest uninterrupted sequences of trades (as shown 

in Appendix II-A, Tables II-A12 and II-A13), in which a single firm 

engages in consecutive trades, took place on December 11, 2000. On 

that day, Reliant bought contracts for 800,000 MMBtu and sold 

contracts for 554,000 MMBtu, resulting in a net purchase of 246,000 

MMBtu for delivery the next day. (Figure II-11 shows the trading 

activity for this day, labeled in the same form as in Figures II-1 and II4 to II-9.) This was a day on which the price varied particularly 

widely, ranging from $34 to $68; much of this variation took place 

during Reliant’s stretches of consecutive transactions. Reliant opened 

its trading for the day at 8:09 a.m. with seven purchases (each for 

10,000 MMBtu) within 45 seconds, during which the price rose from 

$60 to $68. At 8:51 a.m., Reliant sold eight contracts (each for 10,000 

MMBtu) within 28 seconds, during which time the price dropped from 

$60 to $53; the next transaction took place at $43. At 9:02 a.m., 

Reliant bought 10 contracts (each for 10,000 MMBtu) within 62 

seconds, during which time the price rose from $41 to $56. Reliant 

then stayed inactive until 9:11 a.m., when it made another series of 12 

purchases (each for 10,000 MMBtu) in three groups, during which 

time the price rose from $34 to $50. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-28

Figure II-11 

Day-Ahead Trades at SoCal 

December 11, 2000 for December 12, 2000 Gas 

$32.0

$36.0

$40.0

$44.0

$48.0

$52.0

$56.0

$60.0

$64.0

$68.0

$72.0

7:50 7:57 8:04 8:12 8:19 8:26 8:33 8:40 8:48 8:55 9:02 9:09 9:16 9:24 9:31 9:38

Time

Price

Buy from Others Sell to Others Buy from Reliant Sell to Reliant

Average Buy Price from Others Average Sell Price to Others Average Buy Price from Reliant Average Sell Price to Reliant

Average Buy Price Average Sell Price

Reliant’s final position for the day was a net purchase of 246,000 

MMBtu at a total (net) cost of $12,606,000, for an effective net 

average price of $51.24/MMBtu.17 This price is well below the price 

that the other two net purchasers paid on the same day, as well as 

below the day’s weighted average price for sales to Enron, as shown in 

Table II-4. The Gas Daily index for the day reached its all-time high, 

$59.42, and Enron still paid $13 more than that—Enron paid, on 

average, $72.15 for its net purchases of 172,000 MMBtu. 

 

17This calculation assumes no netting arrangement of the sort described elsewhere in 

this chapter. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-29

Table II-4. EOL Trading in Topock Spot Gas, December 11, 2000 

 Firm 

Total 

Purchases 

(MMBtu) 

Total Sales 

(MMBtu) 

Net 

Purchases 

(MMBtu) 

Effective Net 

Average Price 

($/MMBtu) 

Net Purchasers 

 Astra Power, LLC 10,000 0 10,000 64.00 

 Duke Energy Trading and Marketing, LLC 50,000 0 50,000 57.60 

Reliant Energy Services, Inc. 800,000 554,000 246,000 51.24 

 

 Total 860,000 554,000 306,000 52.7018

Net Sellers 

 AEP Energy Services, Inc. 0 5,000 -5,000 55.50 

 Aquila Dallas Marketing, LP 0 10,000 -10,000 60.50 

 Aquila Energy Marketing Corporation 0 90,000 -90,000 63.67 

 Coral Energy Resources, LP 0 25,000 -25,000 59.60 

 Dynegy Marketing and Trade 0 130,000 -130,000 57.46 

 Enserco Energy, Inc. 0 30,000 -30,000 62.13 

 Mirant Americas Energy Marketing, LP 0 48,000 -48,000 63.00 

 PG&E Energy Trading-Gas Corporation 0 10,000 -10,000 36.00 

 San Diego Gas & Electric Company 0 20,000 -20,000 43.00 

 Sempra Energy Trading Corp. 0 30,000 -30,000 62.33 

 Southern California Gas Company 0 60,000 -60,000 63.83 

 Texaco Natural Gas Inc. 0 15,000 -15,000 55.33 

 Tractebel Energy Marketing, Inc. 0 5,000 -5,000 65.00 

 

 Total 0 478,000 -478,000 59.7019

 All External Firms (excluding Enron) 860,000 1,032,000 -172,000 

 Enron 1,032,000 860,000 172,000 72.1520

 

18Weighted average of effective net average price for net purchasers, using the net 

purchases as the weight. 

19Weighted average of effective net average price for net sellers, using the net 

purchases as the weight. 

20Calculated as Enron’s net payments of $12,409,500, divided by net purchases, 

172,000 MMBtu. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-30

Reliant’s Trading Had the Effect of Maximal Market Impact 

In Figures II-4 to II-6 above, one of the most visually striking elements 

is the nearly vertical line formed by the consecutive strings of 

Reliant’s purchases and sales. When Reliant churned, it apparently 

made no effort to mask its activity. If anything, the opposite was the 

case. 

Reliant’s purchases typically took place in bursts, with successive 

purchases made at increasingly higher prices, seemingly running 

through the EOL “stack.”21 Given that there were sometimes more 

than a dozen purchases in a burst, it is quite possible that Reliant’s 

bursts completely exhausted the stack. The same holds true for sales. 

Often when Reliant sold, it entered into several transactions in rapid 

succession, bringing prices down. In most cases, the net effect was an 

increase in prices (examined in more detail below). 

Reliant’s transaction pattern looks like the opposite of the usual 

expectation—buyers usually seek to minimize the extent to which they 

increase prices, and sellers usually seek to minimize the amount by 

which they bring prices down. 

Reliant’s Churning Raised the Index Prices 

Because the published indexes report a midpoint (or an average) price 

for a day’s trading, the churning activity inherently would bias the 

reported midpoint even if the churning had not affected closing prices. 

When an index is based on an intraday average, the manner in which 

churning takes place is bound to affect the published index price. In 

the case at hand, churning raised prices, as Reliant typically began by 

buying and then later selling. In so doing, the initial buys raised prices. 

While the selling brought prices back down, the churning raised the 

day’s median (and average) price. 

For example, assume the day’s prices open at $5/MMBtu and a 

company needs to purchase 50,000 MMBtu and uses one of two 

buying strategies. In the first strategy, it simply buys 10,000 MMBtu 

five times in a row and acquires the 50,000 at a median (and average)

price of $5.20 (e.g., purchases of 10,000 MMBtu at prices of $5, 

$5.10, $5.20, $5.30, and $5.40, respectively). 

 

21Essentially, the stack is a queue of bids and asks that the Enron trader would 

maintain in order to quickly replace a bid or offer when it was accepted by a 

counterparty, so that the product would remain available on counterparty traders’ 

screens at all times. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-31

In the second strategy, the company chooses to buy 30,000 MMBtu 

more (for a total of 80,000 in purchases) and then sell that 30,000, 

resulting in the same net purchase amount of 50,000. Using the same 

price pattern as above, purchases 6, 7, and 8 are made at prices of 

$5.50, $5.60, and $5.70, and the three sales are made at $5.70, $5.60, 

and $5.50. Although the net amount purchased equals 50,000 MMBtu, 

the median transaction price for these 11 transactions is $5.50, $0.30 

higher than under the first strategy. The company’s own average 

purchase price, however, remains the same, at $5.20. 

Larger amounts of churning (where, as in Reliant’s case, the sequence 

consisted of purchases followed by sales) would produce larger 

increases in the median and average prices. 

Even if the day’s closing prices for the two scenarios are the same, 

prices will have been higher throughout the trading day under the 

second strategy.22

Churning on EOL Showed Price Gyrations to the Whole Market 

It is our understanding that virtually every gas trader had an EOL 

screen. EOL served as a common source for “price discovery”—

traders looked to EOL for the current market price. One reason for this 

was that Enron always posted a “two-way”—a price at which it was 

willing to buy and a price at which it was willing to sell—and it is our 

understanding that Enron worked to keep its bid-ask spread as narrow 

as possible. 

One implication of EOL’s bid-ask prices, and changes in the bid-ask 

prices, being constantly observed by all gas traders is that as Reliant 

bought and sold in bursts, the whole market would see the resulting 

rapid, pronounced price movements. However, only Enron and Reliant 

would know why prices were moving when Reliant churned: 

♦ Reliant always knew when its transactions were completed 

successfully, i.e., when its bids were accepted. So Reliant could 

see what happened to prices as it engaged in numerous successive 

transactions. 

♦ Enron could see even more. Enron saw Reliant’s activity along 

with every other trader’s transactions and attempted transactions. 

 

22However, forming index prices by using only transactions near the end of the 

trading day would risk manipulation of the shorter price-setting interval. The risk of 

manipulating closing prices might be larger than that of manipulating a day’s worth 

of prices. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-32

Other traders could see only that the prices on their EOL screens were 

seesawing up and down—in a manner not observed at other trading 

locations. With all that was going on in the western energy markets at 

this time, particularly in December 2000, it would be difficult to 

surmise what these traders were thinking. However, they could not 

know what only Enron and Reliant knew. 

EOL was the most public place possible for Reliant’s trading 

activities. In interviews (described further below), Reliant’s SoCal spot 

traders indicate that they did not view their spot market purchasing 

patterns as unusually affecting the market. They stated that purchasing 

a relatively large quantity of gas might or might not affect prices, but 

that the way they went about buying and selling did not. On its face, 

this seems implausible. Reliant is the only firm that consistently “hit 

the button” rapidly and repeatedly, and Reliant did so only at the 

SoCal border. The graphs of entire days of trading are perhaps most 

telling in that they display both the rapidity with which Reliant was 

trading and the price movements that came with those bursts of 

trading. Figure II-5 shows that prices rose straight up when Reliant 

made its numerous bursts of purchases and prices dropped 

precipitously (although not as far) when Reliant sold in bursts. Reliant 

would have Staff believe that it bought large amounts in quick bursts, 

saw prices rise immediately, and tried to sell back on EOL at the 

highest of these prices, but had no idea that it was affecting market 

prices. 

Reliant’s Western Market 

Gas Trading Operations 

In our review of trading records, it became clear that a single Reliant 

trader was responsible for all of Reliant’s churning and almost all of its 

SoCal trading. 

On Enron’s side, two Enron traders shared responsibility for trading 

SoCal spot gas. On any day, one of these two traders would transact all 

of Enron’s trades. Over time, each of these two traded Topock roughly 

equally. Both of these Enron traders were counterparties in the 

anomalous trading patterns, in approximately equal proportions. They 

traded Topock almost exclusively—when they were not trading spot 

gas at Topock, they were not trading much of anything else. Given that 

it is the counterparty that initiates all transactions, we decided to focus 

on Reliant’s side of these transactions.23

 

23From Enron’s perspective, the churning may not have been looked upon as 

problematic because Enron knew when it was taking place and who was doing it. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-33

Given that the transaction patterns appeared to place no emphasis on 

minimizing the market impact of engaging in successive bursts of 

transactions, we considered a number of alternative hypotheses that 

might explain the observed trading patterns. Some of the possibilities 

are more benign than others. Possible alternatives included: 

5. Reliant’s SoCal trader was given a set of instructions—e.g., to 

transact primarily on EOL or to buy a specified quantity and/or to 

“balance” Reliant’s needs—but was not responsible for the price 

paid (perhaps since it considered EOL liquid and robust). 

6. The Reliant trader simply did not care about prices paid, and was 

unsupervised. 

7. The trader’s compensation structure gave an incentive to churn—

e.g., the trader was allowed to buy and sell on account while filling 

Reliant’s physical needs, and was somehow rewarded for churning. 

8. Something more deliberate—e.g., a strategy of trading on EOL to 

drive up prices and benefit a financial position as well as 

potentially profit from the physical trades. A key question to 

address in this regard is whether higher index prices benefited 

Reliant’s financial positions (discussed below). 

Each of these possibilities has implications for the motivations and 

oversight of Reliant’s management. Reliant may have been unaware 

that its SoCal spot trader was moving prices. Or, Reliant may have 

been unconcerned—or pleased—by such trading. In our examination 

of Reliant’s behavior during this time period, among the steps we took 

were to examine Reliant’s physical and financial trading records for 

southern California. This included: 

♦ All Reliant physical trading on EOL, since this is where the index 

prices would be affected most directly. 

♦ Reliant’s SoCal trading in swaps, basis swaps, and balance-ofmonth swing swaps. 

♦ All Reliant physical and financial trading with all counterparties, 

not just Enron on EOL. 

♦ Examination for linkages between Reliant’s financial trading 

activity and Reliant’s anomalous EOL trading days. 

After the Initial Report was published, Staff held interviews with 

Reliant traders and reviewed several key documents. In these 

interviews, Reliant reported that approximately 70 percent of its 

 

Additionally, it raised trading volumes and observed price movements, making the 

trading platform look both more vibrant and more liquid. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-34

purchases in this time period were made on the spot market. In our 

discussions with Reliant traders and management, and from our review 

of Reliant’s trading records, we gained an understanding of how 

Reliant carried out its trading activity, why this behavior took place at 

Reliant, and why Reliant stood out on EOL. A key factor in Reliant’s 

gas operations was its contract with LADWP. During this time period, 

Reliant held a contract with LADWP to meet LADWP’s gas needs for 

its power plants. 

LADWP Contract 

Reliant became LADWP’s gas supplier in the summer of 1999, for a 

term of 1 year. This contract was renewed for an additional year; the 

second year includes the refund period. 

Under the contract, LADWP was responsible for providing Reliant 

with estimates of its gas needs. LADWP was to make a monthly 

baseload nomination and subsequent daily swing nominations, and 

Reliant would then deliver gas to LADWP accordingly. 

The pricing terms for this contract reflected the nominations 

arrangement. The price LADWP paid for its baseload nominations was 

based on the NGI monthly index. The price LADWP paid for its spot 

gas was based on the Gas Daily daily midpoint price. Three key 

implications of this contract structure are: 

♦ Reliant would profit to the extent it could beat the published index 

prices. 

♦ Reliant could minimize its price risk by matching its purchases for 

LADWP to LADWP’s nominations, rather than (for example) 

holding a larger gas purchase portfolio and serving LADWP from 

it. 

♦ LADWP did not benefit from Reliant’s churning profits. 

Southern California Gas Balancing Rules 

Customers, such as Reliant, that used the SoCalGas intrastate system 

to serve customers had to contend with the SoCalGas balancing rules. 

In general, customers were expected to deliver gas in quantities that 

matched their usage. SoCalGas allowed its customers some tolerance 

from exactly matching nominations with usage. This tolerance was 

more stringent during the winter than the summer, and in the winter it 

was more stringent when physical system conditions—principally 

aggregate system storage levels—dictated it. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-35

The SoCalGas balancing rules are regulated by the California Public 

Utilities Commission (CPUC). In all cases, balancing charges are 

invoked for a customer’s failure to deliver sufficient quantities of gas. 

The level of the penalty is generally set at 150 percent of the highest 

reported spot price (over some relevant time period) multiplied by the 

amount the balance is below the tolerance. The balancing tolerance 

varies with SoCalGas’s aggregate system storage balances. 

Also, balancing rules are more stringent during the gas winter 

(November to March), including a set of triggers, based on the 

quantity of gas SoCalGas has in storage.24 SoCalGas requires that 

customers deliver at least 50 percent of usage over a 5-day period from 

November through March. As SoCalGas’s total (i.e., not customerspecific) storage inventory declines through the winter, the delivery 

requirement becomes daily and increases to 70 percent or 90 percent, 

depending on the level of inventory relative to peak-day minimums.25

Monthly Tolerance is 10 Percent 

SoCalGas’s monthly balancing charges apply to imbalances beyond 10 

percent of the customer’s usage for the billing period. Imbalance 

quantities beyond the 10 percent are subject to separate charges for 

underdeliveries and overdeliveries. Underdeliveries beyond the 10-

percent tolerance band incur a charge calculated at 150 percent of the 

highest daily border price index at the Southern California Border for 

the month that the imbalance is created. The highest daily border price 

index is an average of the highest prices from NGI’s “Daily Gas Price 

Index—Southern California Border Average” and the Gas Daily

“Daily Price Survey— SoCal Large Packages Midpoint Price.” 

November 1 to March 31 

From November 1 through March 31, SoCalGas transportation 

customers (such as Reliant) are required to deliver a minimum of 50 

percent of usage over a 5-day period. In other words, for each 5-day 

period, if the total delivery is less than 50 percent of the total gas 

usage, a daily balancing charge is set at 150 percent of the highest 

Southern California Border price during that 5-day period (as 

published in NGI’s Daily Gas Price Index). 

Therefore, a single high-priced transaction, as reported by NGI, can 

raise imbalance penalty amounts considerably. This can have its own 

“death spiral” effect—any customer thinking it will face the 150-

 

24During the summer, SoCalGas applies a monthly charge only; the charge can be 

avoided by being no more than 10 percent out of balance for the month in total. 

25Customers, such as Reliant, can hold storage capacity on SoCalGas’s system. 

Reliant held no storage. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-36

percent penalty charge will be willing to pay more than the current 

market price for gas to restore balance and avoid the charge. The result 

of this is that it raises the level of the 150-percent charge for everyone 

facing it. 

The 70-Percent Rule 

At the beginning of the winter, SoCalGas is required to have a certain 

amount of gas in storage. Additionally, there is a peak-day minimum 

requirement that there be sufficient gas in storage to provide 

deliverability for the core 1-in-35-year peak-day event, firm 

withdrawal commitments, and noncore balancing requirement. When 

total SoCalGas storage inventory declines to a predefined (and CPUCregulated) “peak-day minimum + 20,000,000 MMBtu trigger,” the 

minimum daily delivery requirement increases to 70 percent. 

Customers are then required to be balanced at a minimum of 70 

percent of usage on a daily basis and the 5-day period no longer 

applies. The daily balancing standby rate is 150 percent of the highest 

Southern California Border price per NGI’s Daily Gas Price Index for 

the day and is applied to each day’s deliveries that are less than the 70-

percent requirement. 

For example, if on a given day when the 70-percent rule is in effect, 

total usage is 50,000 MMBtu and total deliveries are 30,000 MMBtu, 

then 5,000 MMBtu is subject to the daily balancing charge (70 percent 

times 50,000 minus 30,000 equals 5,000). 

The 90-Percent Rule 

When total SoCalGas storage inventories decline to the peak-day 

minimum + 5,000,000 MMBtu trigger, the minimum daily delivery 

requirement increases to 90 percent. Customers are required to be 

balanced at a minimum of 90 percent of usage on a daily basis. Similar 

to the 70-percent rule, the 5-day period no longer applies. The daily 

balancing charge is 150 percent of the highest Southern California 

Border price per NGI’s Daily Gas Price Index for the day. 

Storage Balances Are Published 

Information regarding the established peak-day minimums, daily 

balancing trigger levels, and total storage inventory levels is made 

available on a daily basis on SoCalGas’s Web site. 

Having Gas in Storage Is Useful for Meeting the Balancing Requirements 

There are a number of ways in which holding firm SoCalGas storage 

rights—and having gas in storage—can benefit a customer: 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-37

♦ Customers, such as Reliant, can nominate gas from storage to meet 

the 70-percent and 90-percent rules. 

♦ At the customer’s option, SoCalGas will use firm storage 

withdrawal volumes on behalf of the customer to match the 

customer’s actual usage, as long as the customer has firm 

withdrawal rights and gas in storage. 

♦ SoCalGas accepts intraday nominations to increase deliveries 

(including from storage). 

What Happened in the winter of 2000–2001 

During the winter of 2000–2001, SoCalGas gas storage balances 

dropped below the threshold level for switching from 5-day balancing 

to daily balancing on January 21, 2001, requiring customers to deliver 

70 percent of their daily usage. As noted above, the penalty for being 

short was then set at 150 percent of the highest daily spot price. 

The 70-percent requirement shifted to 90 percent on February 15, 2001 

and lasted until March 17, 2001. During this period, each customer 

was required to deliver 90 percent of its daily usage or face the penalty 

set at 150 percent of the highest daily spot price. 

From March 17, 2001 to March 31, 2001 (the end of the gas winter), 

SoCalGas operated on daily 70-percent balancing. 

Because the imbalance penalties could be quite onerous, customers on 

SoCalGas’s system needed to factor into their trading and nominating 

strategies the possibility of being assessed these penalties. To meet the 

balancing requirements, customers were willing to pay almost any 

price for gas because the alternative was to pay a penalty equal to 150

percent of the highest priced transaction reported by the index 

publishers. Reliant was one such customer. 

Interview With Reliant’s Southern California Spot Gas Traders 

Staff interviewed Reliant’s SoCal physical spot market traders26 in 

September 2002. The intent of this interview was to learn more about 

how Reliant had carried out its trading operations during the time 

period of interest and about Reliant’s primary SoCal physical spot 

market trader’s role in particular. 

From our review of Reliant’s trading operations, we learned that these 

operations are divided between gas, power, and financial, and are split 

 

26On any given day, one Reliant trader would perform this role. For virtually all of 

the time period of interest, one particular Reliant trader performed this function. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-38

geographically within each of those areas. Reliant’s SoCal physical 

spot market trader worked in the physical gas trading area of Reliant, 

focusing on southern California spot market gas. 

Reliant’s primary SoCal physical spot market trader’s background 

includes both trading experience as well as employment in the research 

department at NYMEX. Essentially, this person came to Reliant with 

the plants that Reliant bought from Southern California Edison, where 

this person had been working as a gas buyer. As a new Reliant 

employee, this person continued in the role of gas buyer and took on 

the added responsibility of servicing LADWP’s spot gas needs, which 

approximately doubled this trader’s responsibilities. 

Unlike the rest of Reliant’s gas traders, Reliant’s primary SoCal 

physical spot market trader worked from home in the Los Angeles area 

and had limited interactions with the rest of Reliant’s traders. Reliant’s 

primary SoCal physical spot market trader reports that the main 

contact person was Reliant’s head of gas trading. 

Reliant’s SoCal physical spot market trader’s primary responsibilities 

were to determine and meet the gas needs of Reliant’s power plants 

and to meet its commitments to LADWP. The trader did this by 

communicating with personnel at the various plants and incorporating 

their estimates. Reliant would purchase all of the swing gas needed, 

which kept them quite busy during this period. A key responsibility 

was trying to avoid incurring the penalties from SoCalGas described 

above (and to which we return below). 

Reliant’s primary SoCal physical spot market trader states that trading 

typically lasted from 6:45 to 8 a.m. California time, a 75-minute 

interval. EOL trading records confirm that trading lasted about 75 (or 

as long as 90) minutes (although the exact time interval reported by 

Reliant’s primary SoCal physical spot market trader varies from what 

we see on EOL). LADWP’s nominations were due to Reliant at 7 a.m. 

California time. Trading on EOL for spot gas at the Arizona border 

typically stopped at about 7:30 a.m. California time (EOL used the 

Central time zone for time reporting purposes.) 

It is clear that the time available was quite limited. On many days, as 

noted above, Reliant’s primary SoCal physical spot market trader 

purchased (net) more than 300,000 MMBtu of gas from EOL alone 

(see Appendix II-A, Table II-A2). 

Reliant’s primary SoCal physical spot market trader’s volume of gross 

transactions was often much larger, on one day reaching as high as 

1,740,000 MMBtu, all of which was purchased in the typical EOL 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-39

maximum increment of 10,000 MMBtu. On that day, this trader’s 

transactions were carried out in approximately 51 minutes, and 90 

percent were carried out within a 30-minute interval, an average of 

one trade every 10 seconds. 

Reliant’s primary SoCal physical spot market trader offered several 

reasons for trading so extensively on EOL: 

1. Availability/liquidity—Enron was always willing to transact, and 

the trader believed Enron’s EOL prices were as good as any others 

and better than any other trading platform. 

2. The view that one was not trading with Enron per se, but with a 

seller matched to one’s purchases. 

3. The netting arrangement this trader had with Enron (described 

below). 

4. This trader’s view that cuts at Topock were more predictable than 

those at Ehrenberg—that the benefit of any higher average flow at 

Ehrenberg would be more than offset by a perceived greater 

variance in cuts. 

Netting Arrangements for El Paso Cuts 

Reliant’s netting arrangement with Enron had two important 

characteristics. The first was that purchases were treated at the average 

cost. A concern at this time for all buyers was the way in which a 

counterparty handled the cuts from El Paso. During this period, it was 

not unusual to expect a 40-percent cut in purchases at Topock. An 

entity selling gas might invoke price majeure—upon receiving its cuts 

from El Paso, the seller would then cut its counterparties in order of 

price. Accordingly, getting a lower price on a transaction might bring 

with it a lower probability of flow. This concern was especially 

important to Reliant, as it was such a large buyer in the spot market. 

The netting arrangement used average prices so that lower cost 

purchases could no longer be targeted for cuts. This gave Reliant an 

incentive to trade on EOL as a general matter. 

The second important feature of the arrangement was that purchases 

were sheltered from cuts altogether up to the amount of sales made to 

Enron and any net profits from the sales were retained by Reliant. All 

of Reliant’s purchases from Enron would be taken together to form a 

volume-weighted average price. All Reliant sales to Enron would be 

combined in the same way. When there are both sales and purchases, 

there are two separate calculations. The matching amounts (sales and 

purchases) would first be netted out against each other and the balance 

would then be settled at the respective average price. This is the 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-40

critical netting feature of the arrangement that gave Reliant an 

incentive to churn on EOL. 

To see the effects of the netting feature, consider an example in which 

Reliant bought 200,000 MMBtu from Enron at an average price of $10 

and sold 100,000 MMBtu at an average price of $15 on a particular 

day. 

In one approach to handling this day’s trades, shown in Table II-5, a 

40-percent cut is applied to net purchases of 100,000 MMBtu and 

Reliant would purchase 60,000 MMBtu from Enron at an average 

price of $5/MMBtu, or $300,000.27 

Table II-5. Netting Example—Settlement Without Netting 

Quantity 

Transacted 

(MMBtu) 

Average 

Transaction 

Price 

($/MMBtu) 

Transaction 

Amount 

($) 

Total buys 200,000 $10.00 -2,000,000 

Total sells 100,000 $15.00 1,500,000 

Net purchase 100,000 -500,000 

Average purchase price $5.00 

Actual flow 60% 

Reliant's purchase price 60,000 $5.00 -$300,000 

The actual netting agreement between Reliant and Enron worked as 

described in Table II-6. All of Reliant’s purchases from Enron would 

be taken together to form a volume-weighted average price. All 

Reliant sales to Enron would be combined in the same way. When 

there are both sales and purchases, the matching amounts would first 

be netted out against each other and the balance would then be settled 

at the respective average prices. 

 

27We use a 40-percent cut level as this is consistent with what has been represented 

to us by numerous sources as a typical cut level. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-41

Table II-6. Netting Example—Settlement With Netting 

If, on a given day, Reliant bought 200,000 MMBtu from Enron at an 

average price of $10 and sold back 100,000 MMBtu at an average 

price of $15, then 100,000 MMBtu would be netted out, with Reliant 

profiting $500,000 from the price spread. According to Reliant, this 

calculation is done first and, regardless of the cuts, the $500,000 profit 

to Reliant would not be affected. If the remaining amount purchased 

from Enron were cut by 40 percent, Reliant would be billed for 60,000 

MMBtu at the average purchase price of $10, or $600,000. This would 

result in a net cost to Reliant of $100,000, with the full profit from its 

sales netted against its net purchase amount. This results in a purchase 

price for the 60,000 MMBtu of only $1.67/MMBtu. In fact, if the 

entire net purchase of 100,000 were cut, Reliant would still retain its 

$500,000 profit. Thus, purchases are sheltered from cuts up to the 

amount of sales and any net profit on the sales is retained. 

Thus, there was a financial incentive to churn. Traders who think they 

can do better than average (presumably most traders) can lock in gains 

by churning, in a way that could not have been done without the 

netting arrangement (and that would have existed had there not been 

cuts on El Paso). Reliant’s primary SoCal physical spot market trader 

reports that the netting arrangement was verbal, i.e., there was no 

paperwork. 

It can be shown mathematically that whenever Reliant was a net buyer, 

there was a benefit to the netting arrangement that equaled the product 

of the price difference, the percentage cut (1 – the percentage 

delivered), and the quantity sold.28

 

28Assume that Reliant buys X (MMBtu) gas from EOL at price A ($/MMBtu), and 

sells Y (MMBtu) gas to EOL at price b ($/MMBtu). Suppose for this day’s trades, 

the actual delivery rate is k percent. Without the netting agreement, Reliant pays aX 

dollars for the gas they bought and gets bY dollars for the gas they sold. In total, 

Quantity 

Transacted 

(MMBtu) 

Average 

Transaction 

Price 

($/MMBtu) 

Transaction 

Amount 

($) 

Offsetting buys 100,000 $10.00 -1,000,000 

Offsetting sells 100,000 $15.00 1,500,000 

Netted amount 100,000 $5.00 $500,000 

Additional purchase 100,000 $10.00 

Actual flow 60% 

Flowed quantity 60,000 $10.00 -$600,000 

Reliant's purchase price 60,000 $1.67 -$100,000 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-42

Reliant’s total profits from the netting agreement are shown in Table 

II-7. The table shows that profits from the netting arrangement were 

$8.9 million and that the majority of the profits came on days when 

Reliant churned. 

Table II-7. Reliant’s Profit From EOL-Reliant Netting Agreement, 

November 2000 – June 2001 

24 Churn Days All Other Days Total 

Profit from 

the Netting 

Agreement $7,267,962 $1,541,962 $8,809,924 

Percentage 82.50% 17.50% 100% 

Table II-8 shows the average purchase price that Reliant paid for gas 

under the netting agreement compared with what it would have paid if 

there were no netting agreement in place. It shows that the effective 

price differential (with and without the netting agreement) is 

substantial for churn days ($0.76/MMBtu) and negligible on other 

days ($0.03/MMBtu). 

 

Reliant pays (aX - bY) dollars if all net purchases were delivered. When some gas 

gets cut, that is, when k percent is less than 100 percent, the total amount of money 

Reliant needs to pay to EOL is (aX - bY) * k. With the netting agreement, the churn 

portion of the buy and sell will cancel each other out first and a cash credit is given 

for every MMBtu if the sell price is higher than the buy price. The net purchase is 

then settled at the buy price. If Reliant acts as a net buyer (X > Y), the total amount 

of money it needs to pay to EOL is (X - Y) * a * k - (b - a) * Y. The possible 

advantage of the netting agreement to Reliant can be measured as: 

 [(aX - bY) * k] - [(X - Y) * a * k - (b - a) * Y] 

 = akX - bkY - [akX - akY - (b - a)Y] 

 = akY - bkY + (b - a)Y 

 = (b - a)Y - (b - a)kY 

 = (b - a)(1 - k)Y 

That is, the advantage is the product of the price difference (sell-buy), the percentage 

cut, and the quantity sold. If Reliant acts as a net seller rather than a net buyer, the 

advantage of the netting agreement is the product of the price difference (sell-buy), 

the percentage cut, and the quantity bought. For a net buyer, the sell quantity Y is the 

churn quantity (the quantity that gets netted out). For a net seller, the buy quantity X 

is the churn quantity. Therefore, as buyer or as seller, Reliant’s profit would increase 

proportionally to the churn quantity, independent of its actual net purchase or sales 

quantity. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-43

Table II-8. EOL-Reliant Netting Agreement’s Impact on Physical Spot 

Trading Outcomes, November 2000 – June 2001 

24 Churn 

Days 

All Other 

Days 

Total 

Without the 

Netting 

Agreement $24.36 $15.35 $17.08 

Average 

Buy Price 

Applying Profit 

from the Netting 

Agreement, 

Assuming 60% 

Flow $23.60 $15.32 $16.91 

Note: Reliant was a net seller for three of the 24 Churn Days. The average buy price 

does not factor in those. 

Tables II-A14 and II-A15 in Appendix II-A provide details of the 

impact of the netting agreement (assuming 60 percent flow) on a daily 

basis for high-profit days (Reliant profit > $100,000). These tables 

show that the highest priced day in market history was also the day of 

the highest profits from netting—December 11. Tables II-A16 and IIA17 provide details of the impact of the netting agreement on a daily 

basis for all churn days. These tables show that Reliant lost money 

from netting on only 3 of 24 days, and that the total amount of losses 

was less than $30,000. In contrast, the netting arrangement resulted in 

a number of days of significant upside for Reliant. Tables II-A18 and 

II-A19 provide details of the impact of the netting agreement on a 

daily basis for all days in December 2000. These tables show that 

Reliant’s profits from netting were approximately $5 million for 

December; virtually all of the profits occurred in the first 8 days of 

trading, when market prices rose to all-time highs.

Econometric Analysis of Reliant Trading Impact on Gas Prices 

The previous sections of this chapter (along with Appendix II-A) 

document in detail that Reliant’s SoCal trading on EOL stands out. No 

other firm traded in the manner in which Reliant traded, and Reliant’s 

churn trading took place only during a highly unusual period for 

energy markets and only at one particular, key location—the 

California-Arizona border—where prices reached record highs. 

However, this does not tell us whether or to what extent Reliant’s 

trading impacted the market as a whole, which we discuss in this 

section. We performed the impact analysis in two steps: 

1. We determined whether prices rose during the trading interval on 

the days Reliant churned. 

2. We calculated the impact of churn on prices. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-44

The first step in this impact analysis focused on the trading interval 

itself, as this is when Reliant could have affected the market most 

directly. During the November to June time period, prices generally 

rose sharply when Reliant made an uninterrupted series of purchases in 

a short amount of time. Similarly, we also observe that prices fell 

when Reliant made a burst of sales. The second step examines the 

effect of churn across days. 

As the EOL prices rose and fell, they were seen by virtually all gas 

traders. In fact, as discussed in Chapter III, many traders used EOL as 

their main tool for price discovery and many reported the prices they 

saw on EOL to the Trade Press, who published the gas price indices. 

Intraday EOL Price Analysis 

This section examines whether SoCal prices rose during the 90-minute 

trading interval on the days Reliant churned. For purposes of this 

analysis, we define churn in two ways: 

1. Days on which Reliant both bought and sold at least 100,000 

MMBtu/d. Under this definition, Reliant either churned or it did 

not.29

2. The lesser of Reliant’s daily total purchases and total sales. For 

example, if Reliant bought 50,000 MMBtu and sold 30,000 

MMBtu (for a net purchase of 20,000 MMBtu), the churn variable 

takes on a value of 30,000 MMBtu. 

The following descriptive statistics compare gas prices on churn vs. 

nonchurn days according to the first definition: 

♦ The change in intraday price levels is significantly larger on churn 

days (+9 percent). The average intraday price change is 9 percent 

larger on churn days. 

♦ The average price is more than $9/MMBtu higher on churn days 

($22.02 on churn days vs. $12.79 on other days). 

♦ The minimum price is $17.32 on churn days vs. $11.67 on other 

days. 

♦ The maximum price is $24.56 on churn days vs. $13.85 on other 

days. 

 

29We identified 24 such days for Reliant in the period, while there are only 2 churn 

days for all other counterparties combined across all EOL trading locations in the 

West. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-45

♦ The spread between the maximum and minimum prices is greater 

on churn days, with a $7.24 spread on churn days and a $2.18 

spread on nonchurn days. 

♦ Measured from the start of trading to the close of trading, prices 

rose on average by $1.28/MMBtu on churn days and fell on 

average by $0.30/MMBtu on nonchurn days. 

This suggests that the market behaved differently on churn days. Since 

Reliant churned on some days and not on others, we can examine the 

price impact with some relatively straightforward econometrics. In the 

econometric analysis, we include variables to control for other factors 

in order to determine, all else being equal, if prices rose more (or fell 

less) on days when Reliant churned. The econometric analysis uses 

EOL trading data for November 1, 2000 through June 2001, the period 

when the churning took place. Four variables are used to capture 

factors other than churning: one captures the effect of a transaction 

having taken place in December 2000, a second captures differences 

between Friday trading intervals for Saturday to Monday flow and 

other trading intervals for normal weekday flow, and the remaining 

two variables reflect basin price changes for western Canada 

(measured at Sumas, Washington) and San Juan. 

For both regression specifications, churning is found to be positively 

correlated with intraday gas price changes and is statistically 

significant. Stated differently, when Reliant churned, prices rose on 

EOL and on the indices. The regression results are summarized in 

Appendix II-B. 

We examined whether the results of our econometric analysis were 

robust. For example, changing the threshold for churn from 100,000 

MMBtu/d to a different level (higher or lower) does not change results 

materially. Similarly, the results are also robust to changes in the time 

period considered (i.e., including earlier months along with November 

to June). Similarly, the results are unaffected by: (1) using other basin 

prices, (2) not controlling for the weekend effect or for the December 

effect, and (3) calculating the intraday price change using an average 

of the first few and last few sales rather than the first and last sales. 

With any of these changes to the model, the core result is unaffected—

there is a statistically significant relationship between churning and 

increasing prices. 

The clear statistically significant relationship between the churn 

variable and higher prices in the regression models suggests Reliant’s 

churning artificially raised gas prices. In the next section, we estimate 

the net impact of churning on prices. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-46

Interday EOL Price Analysis 

and Counterfactual Gas 

Prices 

The second step in the impact analysis is to determine the extent to 

which the within-day price increase observed in the first step persists 

across days (i.e., whether the price increase caused by churning carried 

from one day to the next) and to estimate what the prices would have 

been in the absence of churning—i.e., to calculate counterfactual 

SoCal gas prices. By comparing the observed prices with the 

calculated counterfactual prices, we can determine the economic 

impact of churning. 

The calculation of counterfactual gas prices is based on an 

econometric analysis similar to that described in the previous section, 

with some minor differences. First, the analysis examines interday 

rather than intraday price changes. Interday price changes reflect both 

intraday and overnight price changes. Second, the model captures the 

effect of churn on price changes on days after the day on which churn 

takes place, i.e., the model allows us to measure the persistence of the 

effect of churn. We model persistence by including lags of the churn 

variable.30 Third, the model includes variables designed to capture the 

general tendency of prices to revert toward “equilibrium” values. We 

model mean-reversion—the general tendency of prices to revert 

toward “equilibrium” values—by including the lagged level of the 

EOL price and, in some specifications, additional variables. 

Mean-reversion is an important component of energy price movements 

in both the long term and short term. In the long term, high prices 

induce further exploration and production, leading to increased supply. 

To the extent that demand is price sensitive, high prices may also 

reduce demand in both the long term and short term. By inducing 

additional supply and reducing demand, high current prices tend to 

lead to lower prices in the future. Conversely, low prices today tend to 

lead to higher prices in the future. The details of the model 

specifications and counterfactual calculations are provided in 

Appendix II-B. 

We specify mean-reversion in two ways: 

 

30We include three lags of churn in the model, i.e., we measure for churn’s effect on 

price changes up to 3 days in the future. We have obtained qualitatively similar 

results by including different numbers of lags. We also include three lags of the 

relevant control variables. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-47

1. Equilibrium gas price varies as a function of the data. We assume 

that levels of the control variables, such as basin gas prices, 

determine an equilibrium price. Price movements are a function of 

the difference between the lagged EOL Topock price and the 

equilibrium price. To the extent that the lagged price is above the 

equilibrium level, prices tend to fall (i.e., price changes are more 

negative). To the extent that the lagged price is below this 

equilibrium level, prices tend to rise (i.e., price changes are more 

positive). 

2. Equilibrium gas price is assumed to be constant. This is a 

simplification of the first approach. Rather than modeling an 

equilibrium price that can change in response to changes in certain 

variables, we assume that the equilibrium price is fixed. 

Which of these specifications is “better” is ultimately an empirical 

question. 

Regression models are estimated over the entire period for which we 

have EOL data, i.e., February 7, 2000 to June 29, 2001. We focus on 

counterfactual prices from November 1, 2000 forward. This is also the 

period under consideration in the refund case and the period during 

which many long-term power contracts currently subject to litigation 

and renegotiation were signed. 

The regression results are summarized in Appendix II-B. We report 

results for four different specifications based on two methods for 

measuring churn and two methods for modeling mean-reversion. The 

results of all specifications are similar and show that: 

♦ Churn tends to elevate prices close to when it occurs, but the effect 

dissipates after several days. 

♦ In every specification, when prices are high they tend to fall and 

when prices are low they tend to rise. 

♦ Models in which the equilibrium price is allowed to vary fit the 

data better. 

For a single instance of churning (where none takes place in the 3 

trading days prior to or subsequent to the churn day), the 

counterfactual gas price calculation has several steps.31 When churn 

days occur within 3 days of one another, the counterfactual gas price 

calculation is somewhat more complex. The following example 

assumes an isolated day of churn trading: 

 

31The econometric specification uses logarithms. Accordingly, an additional step is 

exponentiation of the logarithmic results. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-48

1. Using the EOL trading data, calculate the observed interday price 

change. 

2. Using the results from the econometric analysis, determine the 

price increase from churn (the model specifies that the percentage 

increase is the same for every day on which churning takes place). 

3. Subtract the churn-related price increase from the actual day-today price change. 

4. Add the difference in step 3 to the previous day’s closing price to 

form the counterfactual gas price. 

5. The difference between the counterfactual gas price and the actual 

price is the amount attributable to churn. 

Using the calculated counterfactual gas price, repeat this calculation 

iteratively for the next 3 trading days, after which we assume that 

actual and counterfactual prices are equal. 

Rather than posit that there is one “true” econometric model that can 

produce counterfactual gas prices, we have performed the analysis in 

four ways that are largely similar to each other but differ in key ways. 

Using this approach, we observe that no matter the model 

specification, the results are essentially the same. Prices would have 

been lower in the absence of churning. The more churning that 

occurred, the higher the market prices. 

One key difference between the models is that two specifications use 

the either-or specification of churn. Any day with more than 100,000 

MMBtu/d of buys and 100,000 MMBtu/d of sells is a churn day. Any 

day with less buying or selling (such as a day with 300,000 MMBtu of 

buys and only 90,000 MMBtu of sells) is not a churn day. This 

specification of churn ignores what might be called “minor” churn 

days. 

The other two specifications use a definition of churn that captures all 

days on which Reliant both buys and sells gas at SoCal on EOL. In so 

doing, these specifications give greater weight to the days with the 

most churning activity, unlike the either-or specifications, but also 

count the minor days of churning on which the behavior is far less 

pronounced. There are many instances of relatively small amounts of 

churning, especially in January, February, and April 2001. 

The second difference between the model specifications is the 

treatment of mean-reversion. Two specifications assume a fixed 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-49

equilibrium price and two allow the equilibrium price to vary across 

time. 

Table II-9 shows counterfactual prices computed from the four 

regressions presented in Appendix II-B. These are estimates of what 

spot prices for natural gas would have been at Topock if Reliant had 

not churned on EOL. We focus on December 2000, the period with the 

highest observed prices, a time span during the period under 

consideration in the refund hearings, and one of the months in which 

refunds potentially are largest.32 The churn effect on gas prices is 

biggest in December because that is when the most churning takes 

place. For December 2000, a simple average of the four specifications’ 

monthly average counterfactual gas prices is $8.54/MMBtu less than 

the average EOL prices. This is not to say that gas prices would have 

been precisely $8.54/MMBtu less in the absence of churning. It is 

simply the average from our four estimates. 

Significant differences between actual and counterfactual gas prices 

also occur in February 2001 (when estimates vary from $1.30 less to 

$2.52 less per MMBtu) and March 2001 (when estimates vary from 

$1.94 less to $3.29 less per MMBtu). 

For other months, the difference between the calculated counterfactual 

gas prices and the EOL and published index prices is lower. In May 

2001, when there were no instances of buys and sells of at least 

100,000 MMBtu/d, the counterfactual prices based on the either-or 

measure of churn are the same as the EOL prices, and the prices based 

on the alternative measure of churn are only 5 to 7 cents lower. 

 

32Because FERC has limited refunds to “spot” transactions, potential refunds are 

larger for months during which significant volumes were transacted through the 

California Power Exchange (PX). The PX ceased trading in January 2001. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-50

Table II-9. Counterfactual Price Summary 

 

 Churn = Buys of at 

least 100,000 

MMBtu/d and Sells 

of at least 100,000 

MMBtu/d 

Churn = Minimum 

of Buy Quantity 

and Sell Quantity 

Month EOL Mean Model 1 Model 2 Model 1 Model 2 

EOL Mean – Average 

of All 4 Models 

November $9.86 $9.65 $9.64 $9.43 $9.26 $0.36 

December $25.26 $17.39 $16.69 $18.09 $14.70 $8.54 

January $12.82 $12.82 $12.82 $12.03 $11.09 $0.63 

February $18.57 $17.27 $17.19 $16.68 $16.05 $1.77 

March $14.76 $12.46 $12.34 $12.82 $11.47 $2.49 

April $13.72 $13.45 $13.44 $12.60 $11.09 $1.08 

May $11.77 $11.77 $11.77 $11.71 $11.68 $0.04 

June $6.06 $5.82 $5.80 $5.90 $5.84 $0.22 

 

Weighted Average: 

$1.91 

 

Model 1 Time-varying equilibrium price assumed to be a function of independent 

variables. 

Model 2 Constant equilibrium price is estimated. 

Physical/Financial Linkages 

in Reliant’s Trading 

If the relationship that has been identified between interday and 

intraday price changes and Reliant’s churning behavior is suggestive 

of Reliant’s influence on spot prices on these days, a reasonable line of 

inquiry is whether Reliant’s financial trading activity also benefited 

from its physical churn trading activity. The trades discussed in this 

section, like the physical trades already discussed, are bilateral in 

nature rather than exchange-traded or exchange-settled. 

In this section, we present an analysis of Reliant’s financial trading 

activity, focusing on how this activity aligns with physical trading 

activity and spot gas prices. We focus on Reliant’s financial trading for 

trading activity just prior to periods of churning.33

 

33In the discussion below, we distinguish between the date that a trade is executed 

(i.e., the “transaction” date on which the trade occurs) and the date for which the 

trade applies (i.e., the “flow” date on which the trade is evaluated relative to a price 

index to ascertain the financial outcome). 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-51

How Gas Swaps Work 

Reliant’s financial trading consists primarily of various forms of 

financially settled swaps. In a swap, two counterparties execute a trade 

in which the buyer pays a fixed, known price for some notional 

quantity of gas and the seller pays a price that will vary with the 

market price (generally based on some agreed-upon price index), 

which will only be known later. Thus, the buyer in a swap transaction 

is going long—making a bet that the market price will rise—and the 

seller is betting that prices will fall. The two types of swaps that we 

examined are explained below: 

♦ “Balance-of-month” (swing) swaps are intramonth swaps that 

applied for the remainder of the month, with settlement based on 

daily spot market prices throughout the duration of the contract. 

Similar to ordinary swaps, the buyer profits if gas prices rise. 

♦ “Basis” swaps are trades in which the buyer pays, for some 

notional quantity of gas, a fixed, known price and receives the “to 

be determined” market price differential between two different 

locations—e.g., SoCal minus Henry Hub. Thus, the buyer in a 

swap transaction is betting that the price difference (the basis 

differential) between SoCal and Henry Hub will rise and the seller 

is betting that the basis differential will fall. 

An example of how a trader can profit from a swing swap is provided 

in Tables II-10 and II-11. Table II-10 shows one of Reliant’s swing 

swap transactions as an example. In the example, Reliant purchases a 

10,000 MMBtu SoCal swap, which begins February 14, 2001 and lasts 

through February 28, 2001. If prices turn out to be higher than 

$17.50/MMBtu, Reliant profits. 

Table II-10. A Swing Swap Trade With Reliant as Buyer 

Buy/ 

Sell 

Volume 

(MMBtu) Price 

Trade 

Date 

Contract 

Begin 

Date 

Contract 

End Date 

Buy 10,000 $17.50 02/12/01 02/14/01 02/28/01 

Table II-11 shows the outcome of the swap. On the first day of 

notional “flow,” gas prices were $17.03 higher than the swap price, 

resulting in a $170,250 profit to Reliant. The next day, prices rose a 

little higher (to $19.29), resulting in additional profits of $192,900 to 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-52

Reliant. Over the next week or so, prices fell back to $17.50 and then 

lower. On February 28, prices were $5.05 below the $17.50 swap 

price, resulting in a loss to Reliant of $50,500 for the day. 

Cumulatively, the swap purchase resulted in a profit of $702,550 to 

Reliant. 

Table II-11. Profitability of Swing Swap 

Flow 

Date 

SoCal 

Index Price 

($/MMBtu) 

Difference 

From $17.50 

Swap Price 

($/MMBtu) 

Realized 

Profit for 

Day 

Cumulative 

Profit From 

Trade 

02/14/01 34.53 17.03 $170,250 $170,250 

02/15/01 36.79 19.29 $192,900 $363,150 

02/16/01 33.25 15.75 $157,500 $520,650 

02/17/01 25.25 7.75 $77,450 $598,100 

02/18/01 25.25 7.75 $77,450 $675,550 

02/19/01 25.25 7.75 $77,450 $753,000 

02/20/01 25.25 7.75 $77,450 $830,450 

02/21/01 24.43 6.93 $69,300 $899,750 

02/22/01 21.69 4.19 $41,900 $941,650 

02/23/01 17.48 -0.02 -$200 $941,450 

02/24/01 12.68 -4.82 -$48,200 $893,250 

02/25/01 12.68 -4.82 -$48,200 $845,050 

02/26/01 12.68 -4.82 -$48,200 $796,850 

02/27/01 13.12 -4.38 -$43,800 $753,050 

02/28/01 12.45 -5.05 -$50,500 $702,550 

Reliant’s Financial Trading 

Activity—Basis Trading and 

Swaps 

Staff analyzed Reliant’s financial gas trades, including basis trades and 

swaps having different effective start dates and durations, to establish 

Reliant’s net financial position at each point in time (i.e., each day) 

over the period of interest. The net financial position takes into 

account any prior trade (possibly occurring as early as several months 

earlier or as late as the previous day) that affects the Reliant financial 

position at the start of the day. The trades that affect the net financial 

position on any day comprise both basis trades (generally monthly) 

and swaps (generally rest-of-month). 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-53

Reliant’s Southern California 

Basis Trades 

Our analysis of Reliant basis trades used the net financial position 

resulting from trading activity that occurred prior to the start of the 

month. We compiled, on a cumulative basis over time, the net 

financial position for basis trades that apply to a given month for 

November 2000, December 2000, January 2001, and February 2001. 

Our calculations do not appear to suggest any type of systematic 

positions or trading activity on the part of Reliant that would indicate it 

attempted to structure its financial basis trading behavior so as to 

benefit from its physical trading activities. 

Reliant’s Southern California 

Swaps 

Figure II-12 shows the daily net financial position for Reliant for the 

period November 1, 2000 through February 2001 as a result of 

financial swaps. The figure shows that Reliant’s daily net financial 

position ranged from a short position of 75,000 MMBtu/d on 

November 16, 2000 to a long position of 65,000 MMBtu/d between 

January 20, 2001 and January 31, 2001.34 From November 2000 

through February 2001, there are three subperiods during which 

Reliant changed its net financial swap position markedly from a short 

position to a long position, and maintained the long position for a 

number of days. These three subperiods began on or about December 

1, 2000; January 18, 2001; and February 12, 2001. 

In addition to Reliant’s net financial position, Figure II-12 also shows 

the Gas Daily spot price for SoCal.35 The Gas Daily SoCal spot price 

is relevant because it is the reference price for settlement of Reliant’s 

swaps that apply to a particular day. To the extent that Reliant has a 

net long financial position on a given day, the difference between the 

Gas Daily spot price and Reliant’s weighted average swap buy price 

(i.e., across all trades affecting the net position for the day) will 

determine the profit that Reliant will realize on its net financial 

position for the day. 

 

34The daily swap net position is calculated using the trading records provided by 

Reliant. 

35Gas Daily SoCal Large Packages Midpoint Price. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-54

Figure II-12 

Reliant’s Daily Swap Net Position and Gas Daily SoCal Large Packages Midpoint Price Index 

 November 2000 – February 2001 

Figure II-12 shows that of the three times when Reliant shifted 

noticeably to a net long position (i.e., Reliant would benefit from price 

increases), for two of these periods it did so just prior to a sharp 

increase in the Gas Daily SoCal spot price. If this net financial 

position were taken in anticipation of the spot price increase, Reliant 

would benefit. One hypothesis suggested by the analysis of physical 

trading activity is that Reliant may have influenced prices on certain 

days; one motive would be to reap the benefits of its financial trading 

positions on those days. Collaboration between physical and financial 

trading could explain the timing of the price increase coinciding with 

moving to long net financial positions. 

0

10

20

30

40

50

60

70

11/1/00 11/8/00 11/15/00 11/22/00 11/29/00 12/6/00 12/13/00 12/20/00 12/27/00 1/3/01 1/10/01 1/17/01 1/24/01 1/31/01 2/7/01 2/14/01 2/21/01 2/28/01

Flow Date

GasDaily SoCal Large Packages 

Midpoint Price Index ($/MMBtu)

GasDaily SoCal Large Packages Midpoint Price Index

-100,000

-80,000

-60,000

-40,000

-20,000

0

20,000

40,000

60,000

80,000

11/1/00 11/8/00 11/15/00 11/22/00 11/29/00 12/6/00 12/13/00 12/20/00 12/27/00 1/3/01 1/10/01 1/17/01 1/24/01 1/31/01 2/7/01 2/14/01 2/21/01 2/28/01

Flow Date

Daily Swap Net Position Entering the Day

(MMBtu/d)

Reliant's Daily Swap Net Position Entering the Day

Note: This graph does not show the individual trades. Rather, it shows the cumulative outcome of the trades - the net position. For example, the netposition of 9/1/2000 

may be the outcome of trades made several months prior.
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-55

Subperiod 1: November 27 Through December 31, 2000 

Figure II-13 provides a closer look at the trading activity of a 

particular Reliant trader, “financial trader A,” for one period of 

interest, November 27, 2000 through December 31, 2000. It shows the 

average net position in swaps (for rest-of-December gas) and the 

SoCal spot price for each day. This trader purchased a large number of 

swaps on November 30, 2000.36 As shown in Figure II-13, on 

November 30, 2000 financial trader A made trades that resulted in a 

long position of 85,000 MMBtu/d just prior to a series of 8 

consecutive days of churn trading. The profits associated with 

financial trader A’s financial trading for November 30 to December 1, 

2000, just prior to this period of consecutive churn days, were more 

than $23.4 million (shown in more detail in Table II-A20 in Appendix 

II-A). Essentially, this $23.4 million profit results from the purchase of 

85,000 MMBtu/d of SoCal swing swaps for December, just prior to an 

unprecedented increase in SoCal gas prices and at the beginning of 8 

consecutive days of Reliant churn trading. 

 

36Note that financial trader A accounted for 78 percent of the gross volume of Reliant 

financial swaps for this period. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-56

Figure II-13 

Financial Trader A’s Daily Net Volume Traded for Rest-of-December Gas, 

Compared With Gas Daily SoCal Large Packages Midpoint Price Index 

November 27, 2000 – December 29, 2000 

Subperiod 2: February 6 Through February 24, 2001 

Figure II-14 provides a closer look at financial trader A’s trading for 

the second subperiod of interest, February 6, 2001 through February 

24, 2001. During this period, February 13 trading (for flow on 

February 14) was the only churn day. From February 14 through 

February 24, 2001, gas prices were substantially higher than they had 

been for the first part of February. On February 12, 2001, financial 

trader A bought 13 swaps that resulted in a long position of 70,000 

MMBtu/d. February 12, 2001 was the day prior to the only churn 

trading day in the period, and the SoCal spot gas price of the gas flow 

traded on this day rose sharply to $34.53/MMBtu. The profits 

associated with financial trader A’s financial trading for February 12, 

2001, were $4.4 million. (See Appendix II-A, Table II-A21.) 

36.25

42.02

19.56

54.66 54.66

18.50

18.90 20.26

59.42 54.66

26.60

21.61

18.50 18.50

0

10

20

30

40

50

60

70

11/27/0011/29/0012/1/0012/3/0012/5/0012/7/0012/9/0012/11/0012/13/0012/15/0012/17/0012/19/0012/21/0012/23/0012/25/0012/27/0012/29/00

Flow Date

GasDaily SoCal Large Packages 

Midpoint Price Index ($/MMBtu)

GasDaily SoCal Large Packages Midpoint Price Index

-30,000

85,000

13,000

-4,630 -5,000

1,500 1,500

5,000

-40,000

-20,000

0

20,000

40,000

60,000

80,000

100,000

11/27/0011/29/00

12/1/0012/3/0012/5/0012/7/0012/9/00

12/11/0012/13/0012/15/0012/17/0012/19/0012/21/0012/23/0012/25/0012/27/0012/29/00

Transaction Date

Daily Net Volume (MMBtu/d)

Dailyl Net Volume Traded for Rest-of-December Gas

Note: The orange dots on the index price line show days for which the gas flow was traded on a Churn day.

Note: The Daily Net Volume Traded accounts for contracts starting the next day or the day after and last through the end of the month.
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-57

Figure II-14 

 Financial Trader A’s Daily Net Volume Traded for Rest-of-February Gas, 

Compared With Gas Daily SoCal Large Packages Midpoint Price Index 

February 6, 2001 – February 24, 2001 

 

 

Of the approximately $23 million that Reliant derived from financial 

transactions in December 2000 that were pegged to natural gas spot 

prices at the Southern California Border, approximately $17 million 

was attributable to the increase in physical gas prices caused by its 

churning. Of the approximately $3.8 million that Reliant derived from 

financial transactions in February 2001 that were pegged to natural gas 

spot prices at the Southern California Border, approximately $1 

million was attributable to the increase in physical gas prices caused 

by its churning. In sum, Reliant derived profits from financial 

transactions of approximately $18 million due to churning during the 

relevant 8-month period. 

34.53

0

5

10

15

20

25

30

35

40

2/6/012/7/012/8/012/9/012/10/012/11/012/12/012/13/012/14/012/15/012/16/012/17/012/18/012/19/012/20/012/21/012/22/012/23/012/24/01

Flow Date

GasDaily SoCal Large Packages 

Midpoint Price Index ($/MMBtu)

GasDaily SoCal Large Packages Midpoint Price Index

70,000

-5,000 -10,000

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

2/6/012/7/012/8/012/9/01

2/10/012/11/012/12/012/13/012/14/012/15/012/16/012/17/012/18/012/19/012/20/012/21/012/22/012/23/012/24/01

Transaction Date

Daily Net Volume (MMBtu/d)

Daily Net Volume Traded for Rest-of-February Gas

Note: The orange dot on the index price line shows the day for which the gas flow was traded on a Churn day.

Note: The Daily Net Volume Traded accounts for contracts starting the next day or the day after and last through the end of the month.
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-58

Conclusion Concerning 

Reliant Trading 

At certain times, Reliant employed a churning strategy for buying 

physical spot gas at Topock on EOL. Reliant needed this gas to 

generate and sell power into the spot market and to fulfill its contract 

for supplying gas to LADWP. Reliant’s churning strategy involved the 

repeated buying and selling of substantial quantities of spot gas in a 

very short period of time in amounts far in excess of its actual needs. 

When churning, Reliant often traded in bursts unlike any other trader 

by executing a large number of purchases and sales in a short period of 

time—sometimes entering into transactions at the rate of one every 10 

seconds. No other firm ever made 15 or more trades in a single 

location within 5 minutes; Reliant did this 36 times. Reliant dominated 

the churn trading, accounting for 24 of the 26 instances we found; this 

includes 8 consecutive trading days for December 2000, which 

encompass the highest-ever gas prices in California. Over this critical 

8-day churn period, Reliant’s churn volume comprised more than 70 

percent of its gross trading volume. On the day after this string of 

churning ends, prices drop by more than $25/MMBtu. 

For trading volume, Reliant had the 19 busiest and 24 of the 25 busiest 

trading days on EOL. At Topock and Ehrenberg in particular, Reliant 

had all 30 of the busiest trading days, measured by number of trades 

executed. As such, the assumption of liquidity at Topock was often 

invalid—on a number of days most of the EOL trades took place 

between Enron and Reliant, rather than there being a more diverse mix 

of active traders. For the 3-month period from December 2000 to 

February 2001, nearly 50 percent of the spot gas trades on EOL were 

with Reliant. For the other 5 months of the refund period, Reliant’s 

share varied between 20 and 30 percent. On the day of the highest 

Topock prices (flow date of December 12), Reliant accounted for more 

than 70 percent of the trading volume. 

In addition, Reliant often swamped the Topock delivery point with its 

net gas purchases. On 30 separate occasions, Reliant’s net purchases of 

gas were in amounts greater than half of Topock’s 540,000 MMBtu/d 

capacity. In fact, on two occasions, Reliant’s net purchases exceeded 

the total capacity at Topock. On these days, Reliant’s net purchases 

alone ensured that there would be cuts at Topock. 

Reliant’s rapid-fire sale and purchase of gas in amounts far in excess 

of its needs raised the price of gas on EOL significantly. On average, 

the price is $9/MMBtu higher on churn days than on other days. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-59

Reliant’s churning also resulted in significant price volatility. The 

within-day price spread is $5/MMBtu greater on churn days than on 

other days. 

Reliant was able to benefit from churning even though this raised 

prices and Reliant was a net buyer of gas for its needs. This is because 

Reliant was often able to profit from the price run-up it caused by 

unloading its unneeded gas at the higher prices. In spot market trades, 

Reliant earned more than $8.8 million from its churning and had a 

netting arrangement with Enron that sheltered its sales from cuts on 

the El Paso pipeline. Trading under this arrangement allowed Reliant 

to reduce its average cost of purchasing gas by more than 

$0.75/MMBtu on churn days.37 

Reliant deliberately bought and sold gas in a manner that had the effect 

of raising prices and used its netting agreement with Enron to capture 

the related profits. It used these profits to reduce the total cost it paid 

for the gas it needed. Reliant traded Topock gas almost exclusively on 

EOL, and virtually every trader had an EOL screen. As a result, the 

price gyrations caused by Reliant were seen by the whole market; 

however, only Reliant and Enron knew what was causing the price 

movements. Since EOL served as the primary source for price 

discovery, its prices virtually mirrored those of Gas Daily. Reliant’s 

churning had the effect of moving the entire market price by an 

average of some $8.54/MMBtu for December 2000 and by an average 

of $1.91/MMBtu over the 8-month period that it churned. These 

figures represent the average of analyses we have performed in four 

different ways. All of the analyses are fundamentally alike, but deal in 

slightly different ways with certain input variables. Notably, the results 

of all four analyses are the same—Reliant’s churning raised prices, 

and the more Reliant churned, the higher the prices rose. 

Deliveries into SoCalGas at the California-Arizona border are 

considered as one pricing point in Gas Daily. If we assume that 

Reliant’s trading affected the entire gas volume of 2,500,000 

MMBtu/d delivered into SoCalGas at the California-Arizona border,38

customers paid excessive gas costs in the neighborhood of $650 

million for December 2000 and about $1.15 billion for the 8-month 

period.39 More significantly, if we assume an average load in the 

 

37Assuming 60 percent flow. 

38El Paso into SoCalGas at Topock of 540,000 MMBtu/d and at Ehrenberg of 

1,210,000 MMBtu/d, and Transwestern into SoCalGas at Needles of 750,000 

MMBtu/d. 

39Not all of the gas entering SoCalGas’s system transacts, at least initially, at daily 

index prices. In particular, some gas flows under prices tied to a monthly index. 

However, monthly gas may be resold at index prices and intrastate California 

production may also transact at a price tied to a daily index. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-60

California spot market of 20,000 MW for November through the end 

of the PX in January 2001 and 5,000 MW thereafter through June 

2001, an excessive gas price of $8.54/MMBtu (about $85/MWh) 

would inflate electric clearing prices by some $1.2 billion for 

December 2000. Overall, an excessive gas price of $1.91/MMBtu40

(about $19/MWh) would inflate electric clearing prices by about $1.6 

billion. 

Reliant priced all the spot gas it sold to LADWP at index prices. 

Reliant used the spot gas it purchased for itself to generate and sell 

power at spot market prices, which reflected the indices. Therefore, 

Reliant was largely insulated from the increase it caused in the market 

price of spot gas and effectively bought cheaper gas for itself at 

everyone else’s expense. 

We know Reliant had the ability to unilaterally move the market price 

through churning, and that it did so. Our econometric evidence is clear 

on this point. Second, we know that Reliant had a financial incentive 

to influence prices by churning, and that it profited by doing so. Our 

analysis of the netting arrangement makes this clear. Third, we know 

that churning pushed up the price paid by all participants whose costs 

were tied in one way or another to spot market index prices. 

Recommendation: Remedial 

Action To Address Reliant's 

Churning 

Reliant profited from churning in both the physical and financial 

markets. In so doing, Reliant adversely impacted prices to such a 

significant degree that remedial action is justified. 

The Commission has authority to regulate commodity sales that do not 

constitute “first sales.”41 Sales that are not first sales are sales of gas 

by an interstate or intrastate pipeline, a local distribution company 

(LDC), or an affiliate thereof. During 2000 and 2001, Reliant was an 

affiliate of an interstate pipeline and thus its sales were not first sales, 

i.e., its sales were subject to Commission jurisdiction. In late 2002, 

Reliant was spun off and is no longer affiliated with a pipeline. 

Therefore, its sales are now first sales. 

 

40To form an average for the 9-month refund period, we assume zero churning effect 

for October 2000, for an average price effect of $1.69/MMBtu. 

41First sales are defined in Section 2(21) of the Natural Gas Policy Act of 1978 

(NGPA), 15 U.S.C. § 3301(21) (1994). The Commission does not have jurisdiction 

to regulate first sales pursuant to Section 601(a)(1)(C) of the NGPA, as amended by 

the Natural Gas Wellhead Decontrol Act of 1989, Pub. L. No. 101-60. 
Chapter II 

Docket No. PA02-2-000 Price Manipulation in Western Markets II-61

Section 284.402 of the Commission’s regulations42 authorizes any 

person who is not an interstate pipeline to sell gas for resale in 

interstate commerce at negotiated rates. The gas cannot involve first 

sales but must be within the Commission’s jurisdiction.43 Gas sold by

Reliant is subject to the Commission’s jurisdiction, i.e., it does not 

constitute a first sale because it was sold by an affiliate of an interstate 

pipeline. Reliant’s churning did not violate Section 284.402 of the 

Commission’s regulations because those regulations contain no 

explicit guidelines or prohibitions for trading gas. 

Staff recommends that Sections 284.284 and 284.402 of the 

regulations be amended to provide explicit guidelines or prohibitions 

for trading natural gas under Commission blanket certificates. Staff 

also suggests a generic proceeding to develop appropriate reporting 

and monitoring requirements for sellers of gas under Commission 

certificates.

 

4218 C.F.R. § 284.402 (2002). 

43For example, Order No. 637-A, FERC Stats. & Regs, Regulations Preambles 

¶ 31,099 at 31,603 (1999). (“To the extent that the gas sale is a first sale, it would not 

be jurisdictional, and for jurisdictional gas sales, the Commission has already granted 

a blanket certificate to make sales for resale at negotiated rates.”) 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-1

III. Manipulations of Published Natural Gas Price Indices 

On August 13, 2002, the Commission made publicly available Staff’s 

Initial Report of its investigation in Docket No. PA02-2-000. Staff 

inquired into the characteristics of publicly reported price data, 

including natural gas spot prices at California delivery points that are 

used in the California refund proceeding. Staff found significant 

problems with published price indices and specific issues with respect 

to California delivery point spot prices, as described below:1

 

♦ The Commission cannot independently verify the published price 

data (primarily because the source of the publications’ raw data has 

not been disclosed due to publishers’ confidentiality concerns 

about revealing source data). 

♦ Undetected errors may exist because trade publications reporting 

spot and forward prices do not employ statistically valid sampling 

procedures or a systematic, formal verification procedure. 

♦ Market participants have significant incentives to manipulate spot 

market prices reported to the reporting firms because natural gas is 

the fuel input for the electricity generators that set the market price 

in California. 

♦ Wash trades may have an adverse effect on reported price data. 

♦ EnronOnline (EOL), Enron’s former electronic trading platform, 

was a significant source of price discovery and formation and was 

potentially susceptible to manipulation by market participants, 

which could affect the published price indices. 

Based on these findings, Staff concluded that published California 

delivery point natural gas spot prices are not sufficiently reliable to be 

used in the California refund proceeding for purposes of calculating 

the MMCP and resultant refunds. A detailed discussion of the 

alternative proposal is in Chapter IV. 

 

1

These findings are summarized in the Initial Report on pp. 3-5 and 34; a 

detailed discussion is provided on pp. 35-57. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-2

Developments in the 

Investigation Since 

August 13, 2002 

Since the Initial Report was issued, five companies (Dynegy, AEP, 

Williams, CMS, and El Paso) have admitted that their employees 

provided false data to the Trade Press.2

 On December 2, 2002, the 

Office of the United States Attorney in Houston indicted a former vice 

president of El Paso Energy on charges of false reporting and wire 

fraud in connection with his reporting of false trades to Inside FERC

on November 30, 2001. These false trades were to be part of the 

calculation for the December 2001 monthly price index for the Sumas 

trading point at the U.S.-Canada border. 

On December 18, 2002, the CFTC announced that it had reached a $5 

million settlement with Dynegy and West Coast Power LLC. The 

settlement stated that Dynegy had “knowingly submitted false 

information to the reporting firms in an attempt to skew those indexes 

to Dynegy Marketing & Trades’ financial benefit.” 

On January 26, 2003, Michelle Valencia, a former senior trader at 

Dynegy, was indicted on federal charges of giving false data to Inside 

FERC by the Office of the United States Attorney in Houston. She was 

charged with three counts of false reporting under the Commodity 

Exchange Act as well as four counts of wire fraud. She pleaded not 

guilty. 

On October 22, 2002, Staff sent a data request to the 10 largest natural 

gas marketers and asked a series of questions regarding their past 

reporting practices, any internal procedures or controls they had in 

place, any changes they made in those procedures, and any 

investigations they had in progress. Staff required those companies to 

investigate whether they had misreported data to the Trade Press and 

to provide data on actual trades and reported data so that Staff could 

check the accuracy of those reports. Staff also investigated reporting 

practices of the five companies that admitted that some of their 

employees provided false data to the Trade Press. 

 

2

The El Paso admission came in response to Staff’s October 22, 2002 Data Request 

in Docket No. PA02-2 regarding the price reporting practices of the largest natural 

gas marketers in the United States. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-3

In short, the investigations and responses to the data requests indicate 

that the companies had little, if any, formal procedures in place to 

ensure the accuracy of the data reported to the Trade Press. In fact, in 

some cases there were systematic efforts to bias the data reported to 

the Trade Press for the purpose of trying to offset the perceived 

dominance of Enron’s input to the process, trying to benefit traders’ 

own positions or that of their trading desk, and trying to offset the 

inaccuracies that other companies were reporting. In addition, even 

when these companies claim they were not trying to influence the 

published indices, Staff uncovered cases in which the data were 

inaccurate due to unstructured or nonexistent processes for reporting, 

such as calculating a “volume-weighted average” by taking the simple 

arithmetic average of the high and low trades, making up trades in 

order to come up with an average that was the midpoint of the traders’ 

perceived range, and entering fictitious trades (both prices and 

volumes) in order to replicate what they had seen on EOL or other 

platforms. 

Platts Gas Daily and Platts Inside FERC were the trade publications 

publishing the indices that were most widely used in the industry. Gas 

Daily published a daily price index and Inside FERC published a 

monthly index. Gas Daily published three daily natural gas prices for 

more than 100 pricing points: the absolute range, the common range, 

and the midpoint of the common range. Through interviews (primarily 

via telephone or fax) with natural gas market participants such as 

traders, end users, and producers, Platts reporters collect prices, dates, 

volumes, and sometimes counter parties for individual deals. 

According to Platts, it then sorts prices from low to high, looks for 

“outliers” (those prices that are greater than two standard deviations 

from the mean), cross-checks with counterparties, and calculates 

descriptive statistics (e.g., mean, median, variance, and range). The 

index price is based on this analysis. 

Inside FERC published monthly price indices based on bid-week 

fixed-price transactions for gas flowing the entire next month.3

 Rather 

than calling traders on the phone as was the case with Gas Daily,

Inside FERC had a standardized spreadsheet on which traders were to 

enter prices, volumes, and locations for all fixed-price deals during 

bid-week. The traders e-mailed the spreadsheet to Inside FERC, whose 

editors performed an analysis similar to the one performed by editors 

of Gas Daily to arrive at the published index. 

 

3

A fixed-price transaction is a bilateral deal based on an agreed upon price rather 

than a price based on an index or a basis differential off an index. Generally, a bid 

week begins 5 working days prior to the last trading day of the month, but it can vary 

across regions of the country. A bid-week price is the volume-weighted measure of 

gas prices for the following month done during the pipeline nomination period.
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-4

The investigation and responses to Staff requests for information on 

the data gathering process of the Trade Press were also documented in 

the Initial Report. However, the Trade Press asserted First Amendment 

protection from revealing data, so Staff was unable to get a complete 

picture of the process. After the Initial Report was completed, Staff 

collected pertinent information from the companies that provide data 

to the Trade Press. Having seen the process from the other side, it is 

clear that the information being sent to the Trade Press was subject to 

manipulation and the companies claim there was confusion among the 

traders regarding what the Trade Press was looking for (i.e., all trades, 

only fixed-price trades, observed trades, “feel for the market”), 

particularly in the case of daily indices. However, even when it was 

clear as to what the Trade Press was looking for (i.e., the Inside FERC

spreadsheet), the traders often sent false data. 

Staff also found that traders routinely complained to the Trade Press 

about the accuracy of the indices and that certain large players were, in 

fact, manipulating the indices. Traders report that large players leaned 

on the Trade Press to change indices after they were calculated. 

Further, some companies wrote letters to the Trade Press complaining 

about the methodology (e.g., not requiring counterparties from 

everyone), noting problems, and identifying irregularities. The editors 

of the Trade Press, therefore, were on notice that some of the data they 

were receiving could have been false. As such, sometimes they would 

have had to rely on their judgment and feel for the market rather than 

using a strict calculation. 

Company-Specific Reporting 

Practices 

As stated above, five companies (Dynegy, AEP, Williams, CMS, and 

El Paso) have admitted that their employees provided false data to the 

Trade Press, including Gas Daily and Inside FERC. Some of the 

companies state that they have taken disciplinary actions against those 

employees involved in false reporting, including termination of 

employment and forced resignation. 

This section describes the price reporting practices for each of the five 

companies that have admitted to providing false data to the Trade 

Press. Although the details vary somewhat for each company, there are 

common themes throughout. The reporting was done by the trading 

desks and the traders themselves. There was little, if any, internal 

oversight by management or desk heads. In fact, in some cases, the 

desk heads and management were orchestrating the price 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-5

manipulation. The traders provided false data in order to (1) offset the 

perceived dominance of Enron’s input to the process, (2) benefit 

traders’ own positions or that of their trading desk, and (3) offset the 

inaccuracies that other companies were reporting. 

Moreover, it is clear that the traders understood the process the Trade 

Press used to try to filter out false data and drew on that understanding 

to manipulate prices by constructing phony counterparties and by 

keeping their false data within the range of trading, only reporting 

numbers that favored their position (i.e., traders that wanted to see a 

high price only reported high-priced trades or inflated volumes on 

those trades). 

Dynegy 

On September 25, 2002, Dynegy announced it had discovered that 15 

of its employees had engaged in reporting false data to the Trade 

Press. Of those, seven were fired, four were given the opportunity to 

resign, and four were otherwise disciplined by the company. Dynegy 

interviewed all of its employees who were involved in reporting trade 

data to the Trade Press. The results of the interviews indicated that for 

a number of years the Dynegy trading desks systematically reported 

false data to the Trade Press. Dynegy states that there is no evidence of 

a conspiracy among the trading desks or between natural gas and 

power traders, that it had no systematic method in place for reporting 

trading information to the Trade Press, and that it has moved the 

reporting function to its risk management group. 

The employees who provided false or inaccurate data to the Trade 

Press reported both monthly (Inside FERC and NGI) and daily indices 

(Gas Daily). In their reports to the monthly indices, they fabricated 

trades to come to a predetermined average. For the daily indices, the 

main method of manipulation was inflating volumes of trades. 

Many of the traders stated that they felt pressure from the heads of the 

trading desks to report inflated volumes or prices that benefited the 

desk’s position. One trader reported that the heads of the trading desks 

would instruct traders to report transactions that had not actually taken 

place. Another trader said the desk head told him he had to inflate 

volumes and report false prices. The trader stated that sometime in 

2000 he was told by his boss that “this is how the game is played and 

you need to play it too.” The trader went on to say that on one 

occasion, he took his trading report to his boss, who “told him to go 

back and do the report again, make the volume 2 or 3 times greater and 

make the price range higher or lower” (he could not remember which). 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-6

The trader claimed that he reported inaccurate numbers for 2 months 

and then stopped doing so, and left the company shortly thereafter. 

In addition, some of the fired and disciplined Dynegy traders stated 

that the way in which they reported price data was similar to the way 

in which it was done at their previous companies and they considered 

it to be “common practice in the industry.” 

Many traders reported that they provided a “survey” to Inside FERC

and Gas Daily, whereby they found the “average” of the range of 

trades they observed and/or participated in and then constructed false 

trades to come up with the average. One trader stated that this was the 

same way in which he had reported prices when he was employed by 

another large energy trading company. Many of the Dynegy traders 

stated that they submitted bogus data (particularly to Inside FERC) 

because there were very few fixed-price trades, which is what Inside 

FERC used for its monthly index. In particular, one trader stated that it 

was “widely known” that “there were no fixed-price physical deals at 

some locations.” In addition, traders claim that the heads of the trading 

desks were aware of this and pressured traders to report bogus fixedprice trades in order for Dynegy’s numbers to be reflected in the 

indices. Many of the traders indicated that Inside FERC had to know 

what it was getting from the traders—that is, data on trades that never 

occurred. Specifically, one trader claimed that he provided his trades 

along with what he saw in the market to Inside FERC and that, despite 

the fact that the Inside FERC spreadsheet specifically asked for actual 

fixed-price trades made by the companies, “Inside FERC knew what 

they were getting.” 

Another Dynegy trader stated that he reported trades he saw on EOL 

or the IntercontinentalExchange (ICE) to both Gas Daily and Inside 

FERC because they “wanted to report more than a deal or two,” and to 

show the marketplace that they were a player in it. Another trader 

stated that he felt implicit pressure to inflate volumes because of the 

“fear of bad ranking.”4 

Another Dynegy employee admitted to overreporting volumes because 

of expectations to do so or in response to prices that did not seem fair 

(e.g., those seen on EOL). This employee claimed to “make false 

reports in order to counteract false reports made by others” and said 

the reason for this practice was that this was “as much as a general 

attitude that we needed to fight back” because “the market got 

ridiculous with Enron.” The investigation uncovered evidence of one 

 

4

Staff has not determined whether the ranking refers to the ranking of trading 

companies by volume of trading or the ranking of individual traders or desks within 

the company. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-7

employee instructing other employees to submit false trades in order to 

serve as counterparty so the manipulation could not be detected by the 

Trade Press. 

Staff also found evidence that a Dynegy trader and a trader at another 

company coordinated their numbers in order to report offsetting trades. 

In one case, for example, the Dynegy trader indicates an attempt to 

move the price at one trading point (Malin) down, and therefore only 

reported the low trades to Inside FERC (in the range of $12 to 

$12.50/MMBtu) that occurred during bid week. The other trader 

indicated that its actual trades were around $14/MMBtu. 

In another example, the Dynegy trader and the other trader are 

coordinating their data reporting to Inside FERC for bid week at Malin 

and PG&E citygate—two significant natural gas trading points in the 

western United States. In both cases, the traders are discussing 

coordinating their reporting to ensure that their false numbers are 

included in the index calculation. 

On December 18, 2002, the CFTC issued an Order saying that it had 

reached a $5 million settlement with Dynegy and West Coast Power 

LLC. The Order found that Dynegy had “knowingly submitted false 

information to the reporting firms in an attempt to skew those indexes 

to Dynegy Marketing & Trades’ financial benefit.” 

On January 26, 2003, Michelle Valencia, a former senior trader at 

Dynegy, was indicted on federal charges of giving false data to Inside 

FERC by the Office of the United States Attorney in Houston. She was 

charged with three counts of false reporting under the Commodity 

Exchange Act as well as four counts of wire fraud. She pleaded not 

guilty. 

On January 27, 2003, Dynegy issued the following statement: 

The former employee was one of seven dismissed by the 

company since Oct. 18, 2002, after an ongoing internal 

investigation, conducted by the Dynegy Board of Directors’ 

Audit and Compliance committee in collaboration with 

independent counsel, discovered circumstances indicating 

that inaccurate information regarding natural gas trades was 

reported to various energy industry publications. In addition, 

Dynegy has disciplined seven other employees for their 

involvement in this activity.5

 

5

Dynegy press release, January 27, 2003. www.dynegy.com. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-8

Dynegy further stated that “[t]he past actions by these employees were 

in violation of the company’s policies as outlined in its Code of 

Business Conduct” and that it was “committed to fully cooperating 

with all ongoing investigations into these matters.” 

AEP 

On October 9, 2002, AEP announced that it had “dismissed five 

employees involved in natural gas trading and marketing after the 

company determined that they provided inaccurate price information 

for use in indexes compiled and published by the trade publications.”6

The inaccurate price information referred to in the October 9, 2002 

announcement was for the Gulf Coast region. In response to the Staff 

investigation, AEP officials explained that the traders claimed to have 

been providing false information in order to counteract the false 

information being provided by marketers and traders at other 

companies. 

On October 4, 2002, AEP began an internal investigation of its trade 

data reporting to the Trade Press. AEP states that it initiated the 

investigation in response to the September 25 revelation by Dynegy 

that some of its employees had reported false data to the Trade Press. 

AEP found evidence indicating that some of its employees had 

submitted false data to the Trade Press during the period from 1998 to 

2002. 

The traders claimed to have been instructed by their boss (the head of 

the trading desk) to adjust the prices and volumes of trades they had 

made and, in some cases, to report trades that never occurred. AEP 

claims that the traders indicated that they were doing this because they 

believed it was common practice in the industry, so their false reports 

were only intended to counteract false information reported by 

counterparties. 

The traders were asked how they would know how much to 

manipulate the numbers they reported so as to offset what they 

perceived the other companies were reporting, if these companies were 

presumably reporting simultaneously. The traders responded that they 

had a feel (based on buys and sells) for the way in which the market 

was headed. AEP did not ask the traders whether they tried to 

influence the index in order to benefit their own positions. However, 

they did ask the traders if they ever provided information that they 

 

6

AEP press release, October 9, 2002. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-9

knew in advance would be detrimental to their trading positions, and 

each indicated they had not. 

AEP states that prior to October 2002, there was no process in place 

for gathering or reporting data to the Trade Press. Since its internal 

investigation, AEP has instructed all traders not to provide any data to 

the Trade Press. All trade data will go directly to the head of the 

Market Risk Oversight Group, who will verify that the data are 

accurate and then submit the data to the appropriate publications as 

necessary. 

AEP states that it is continuing its internal investigation and 

cooperating with all relevant regulatory agencies (including FERC, the 

CFTC, and the SEC) as well as the U.S. Department of Justice. AEP 

further states that it has moved the market data reporting function from 

the trading desks to the risk management office. 

Williams 

On October 25, 2002, Williams announced it had learned that a few 

traders in its natural gas trading business provided inaccurate 

information regarding natural gas trades to an energy industry 

publication that compiles and reports index prices. Williams stated that 

the inaccuracies were discovered during an independent, internal 

review of its trading activities. 

Williams hired an outside company to conduct an internal 

investigation of its price reporting. Williams’ investigation of the West 

found no evidence that the daily data provided to Gas Daily over the 

phone were inaccurate. However, the investigation did find that the 

monthly data reported to Inside FERC were inaccurate. Specifically, it 

found that in a number of instances the volume of trades reported to 

Inside FERC exceeded the actual volume of Williams’ trading activity. 

In response to the Staff data request, Williams offers the following 

explanations for the discrepancies: (1) the belief that Inside FERC

expected Williams to report not only transactions to which Williams 

was a party, but other transactions occurring during bid week; (2) the 

reported transaction dates do not necessarily correlate with dates in 

Williams’ database; (3) the reported delivery points do not necessarily 

correlate with delivery points in Williams’ database; (4) ambiguities 

caused by Inside FERC’s requirement that numbers be rounded; (5) 

the evolving nature of the Inside FERC form, which purported to 

narrow the categories of transactions about which information was 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-10

sought over time; and (6) Williams’ traders’ reporting of inaccurate 

information (emphasis added).

7

The review found that some Williams traders manipulated the data 

they provided to the Inside FERC spreadsheet. They stated that they 

were doing this because significant market players (Enron and El 

Paso) were submitting a great deal of false trade data that were outside 

the range of prices that were actually trading, and they were trying to 

offset this false reporting. In addition, they wanted to show the Trade 

Press that they were players in the market. The traders also claimed 

that everyone in the industry, as well as Inside FERC, knew that this 

activity was taking place. They further stated that they believed the 

Trade Press was able to ferret out the most egregious misreporting and 

arrive at generally accurate priced indices. Williams has stopped 

reporting market price data to the Trade Press. 

Williams did, however, find evidence of deliberate attempts to 

manipulate the published price indices in the Northeast. In each case, 

Williams found recorded telephone conversations indicating that 

editors of the Trade Press were questioning the accuracy of the trades 

reported by Williams’ traders. 

In one case, a reporter from Gas Daily indicates that there were very 

few reported trades for that trading point, so the trades reported by 

Williams changed the index by up to 10 cents per MMBtu. The 

reporter from Gas Daily indicates that he was getting numerous 

complaints about the published index price and requests counterparty 

information so he can cross-check Williams’ reported numbers, but the 

Williams trader refuses to provide counterparties due to confidentiality 

concerns. 

In another case, a trader is asked by an editor from Inside FERC to 

provide counterparties for the reported transactions that are on the high 

end of the reported range and appear to be questionable. The trader 

makes up counterparties, but when the editor cross-checks with the 

reported counterparties, they deny being involved in the transactions. 

In addition, an analysis of the financial positions of the Williams 

trading desks indicates that the trading desk profited from the 

movement of the prices. 

 

7

December 13 Response at 5. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-11

CMS 

On November 4, 2002, CMS announced that it was conducting an 

internal review of the natural gas trade information provided to the 

Trade Press by two subsidiaries, CMS Marketing Services and Trading 

and CMS Field Services. CMS stated that a preliminary analysis 

indicated some employees provided inaccurate data to the Trade Press. 

CMS further stated that it would take appropriate disciplinary action 

and it would stop providing information to the Trade Press. 

In its responses to Staff data requests, CMS stated that it had taken 

disciplinary action regarding seven employees (including firing four 

employees, three of whom were regional directors) following its 

inquiry into price reporting practices. 

CMS hired an outside counsel who analyzed the accuracy of the trades 

submitted to Inside FERC from December 2000 to June 2002 for its 

monthly index. Of the 472 trades reported to Inside FERC for that 

period, there were 116 exact matches. The reasons for the 356 reported 

trades that did not have an exact match were: (1) reporting the sense of 

the market, (2) rounding off, (3) aggregation of small deals, and 

(4) reporting what they saw in the market. 

The outside counsel interviewed gas traders and desk heads who 

reported CMS’s trading information to the Trade Press. One trader 

stated that he perceived pressure from his desk head to report 

inaccurate prices (high or low) in order to affect the index price. The 

trader said he resisted the pressure, but on one occasion he did report 

false data in order to manipulate an index to favor the desk’s position. 

According to the trader, during the winter of 2000–2001 the difference 

between the natural gas prices (basis differential) at two significant 

Midwestern trading points was unusually large. The trader’s boss (the 

desk head) wanted him to narrow the basis differential between the 

two prices. The trader then reported high prices for the lower one in 

order to narrow the spread between the two. 

Another trader said that the same desk head asked him to create a 

spreadsheet with fictitious trades designed to narrow another basis 

differential. The trader claims that he did create such a spreadsheet to 

send to Inside FERC and e-mailed it to the desk head. 

There are many financial products traded by energy companies that are 

based on the basis differential between two natural gas delivery points. 

Companies use financial swaps and other instruments to mitigate risks 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-12

they face due to the differences in prices at various delivery locations. 

They also trade basis differentials in order to speculate on those 

differences. Because companies are taking positions based on the 

difference between two points, they can profit if they can affect the 

basis differential by moving one of the prices up and/or moving the 

other price down. Staff has seen examples of both. One method of 

manipulating indices in order to affect basis differentials is to simply 

make up prices, as was the case with CMS. Another way would be to 

only report those trades that favor their positions or inflate the volumes 

of those trades that favor their positions. 

CMS has shut down its energy trading operation, thus it no longer 

reports market data to the Trade Press. 

 

El Paso Merchant Energy 

On November 8, 2002, El Paso Merchant Energy (El Paso) announced 

it found evidence that one of its employees had misreported trade data 

to the Trade Press. El Paso informed Staff that the employee refused to 

talk about the incident to company attorneys and resigned from the 

company on November 12. El Paso states that on November 30, 2001, 

an employee of Inside FERC questioned the accuracy of certain trade 

information submitted by that same El Paso employee. 

On December 2, 2002, the Office of the United States Attorney in 

Houston indicted Todd Geiger, a former vice president of El Paso 

Energy, on charges of false reporting and wire fraud in connection 

with his reporting of false trades to Inside FERC on November 30, 

2001 to be part of the calculation for the December 2001 monthly 

price index for the Sumas trading point at the U.S.-Canada border. On 

December 9, 2002, Mr. Geiger pleaded not guilty to the charges. 

El Paso provided FERC Staff with recordings of telephone 

conversations between El Paso employees and an editor of Inside 

FERC. The tapes are telling in that the Inside FERC editor was trying 

to convince the El Paso traders to provide counterparties for all the 

trades they report in order to “true-up” the index. He explained that 

unless everyone provides counterparties, traders can submit false data 

with no way of being detected as long as the trades are not too far out 

of line with the market. He also explained that once everyone knows 

that the other traders are reporting counterparties, everyone will know 

they must provide accurate data reflecting only fixed-price deals made 

during bid week. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-13

El Paso analyzed the accuracy of its reported data for its Western 

trading desk by comparing what was reported to the Trade Press with 

the actual deals captured in its information system for 728 fixed-price 

trades that took place between October 2000 and December 2001. El 

Paso found that approximately 80 percent of the transactions they 

analyzed were perfectly matched, meaning the price and volume 

reported were exactly the same as the actual price and volume. Of the 

20 percent (145 trades) that were not perfect matches, 23 reported 

transactions had the same price but a volume different from the actual 

transaction. El Paso explains that 115 of the remaining 122 trades were 

within 5 percent of the high and low trading range of the NYMEX 

during the 3-day period comprising 2 business days prior to, and the 

day of, the NYMEX settlement for each particular month, plus the 

published basis index for that month at a particular pricing location. 

An analysis of El Paso’s reporting for the rest of the country (the 

Northeast, Mid-Continent, and Gulf trading desks) shows far less 

accuracy in the reporting than in the West. As shown in Table III-1, 

the percentage of exact matches between actual trades and reported 

trades was 1.2 percent, 1.0 percent, and 0.5 percent for the Northeast, 

Mid-Continent, and Gulf trading desks, respectively. That is, for these 

regions, approximately 99 percent of the reported trades did not 

represent actual trades conducted by El Paso. 

The volumes of the trades are also shown in Table III-1. For these 

three trading desks for the period July 2000 through December 2001, 

El Paso traded 640,568,790 MMBtu of fixed-price physical gas. For 

illustration, if the average price of the gas were $4/MMBtu for the 

period, then the value of the gas would be approximately $2.5 billion. 

So, El Paso misreported 99 percent of the prices on trades worth over 

$2 billion. In addition, as discussed earlier, the published indices are 

the basis for billions of dollars of financial derivative contracts as well 

as physical and financial electricity contracts. 

On January 13, 2003, El Paso updated its disclosures regarding price 

reporting to the Office of the United States Attorney in Houston. 

El Paso disclosed that it had found further instances of inaccurate 

reporting to the trade publications. On January 16, 2003, 

representatives from El Paso and the outside counsel performing the 

investigation briefed Commission Staff on its findings. 

The investigation uncovered evidence that indicated there was 

systematic price manipulation occurring at El Paso. Specifically, prior 

to October 2000, El Paso reported data according to its “book bias.” 

Staff understands that “book bias” refers to El Paso’s trading position. 

In other words, in reporting according to the book bias, if El Paso had 

a long position it would report high prices and if El Paso had a short 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-14

position it would report low prices. That is, it was trying to manipulate 

the published price index in order to favor the company’s financial 

position. 

Table III-1. Price Reporting Summary, July 2000 – December 2001 

No. of 

Deals Percent 

Absolute 

Volume Percent 

Northeast 

Price in range but no deal match 368 84.8% 154,197,500 82.1% 

Price equal to or less than 1% 40 9.2% 20,900,000 11.1% 

Deal found but price and/or volume 

do not match 

0 0.0% 0 0.0% 

Deal price and volume match 5 1.2% 3,487,500 1.9% 

 413 95.2% 178,585,000 95.1% 

Price greater than 1% and equal to 

or less than 5% 

15 3.5% 7,440,000 4.0% 

Price greater than 5% and equal to 

or less than 10% 

5 1.2% 1,550,000 0.8% 

Price greater than 10% 1 0.2% 310,000 0.2% 

 21 4.8% 9,300,000 4.9% 

 

 434 100.0% 187,885,000 100.0% 

Mid-Continent/Midwest 

Price in range but no deal match 388 74.3% 211,827,000 77.9% 

Price equal to or less than 1% 65 12.5% 31,407,000 11.6% 

Deal found but price and/or volume 

do not match 

7 1.3% 2,765,000 1.0% 

Deal price and volume match 5 1.0% 1,540,000 0.6% 

 465 89.1% 247,539,000 91.1% 

Price greater than 1% and equal to 

or less than 5% 

54 10.3% 23,382,000 8.6% 

Price greater than 5% and equal to 

or less than 10% 

3 0.6% 930,000 0.3% 

Price greater than 10% 0 0.0% 0 0.0% 

 57 10.9% 24,312,000 8.9% 

 

 522 100.0% 271,851,000 100.0% 

Texas/Gulf Coast/Southeast 

Price in range but no deal match 1,065 81.5% 546,347,090 85.3% 

Price equal to or less than 1% 94 7.2% 35,728,000 5.6% 

Deal found but price and/or volume 

do not match 

8 0.6% 2,140,700 0.3% 

Deal price and volume match 6 0.5% 1,590,000 0.2% 

 1,173 89.8% 585,805,790 91.5% 

Price greater than 1% and equal to 

or less than 5% 

114 8.7% 46,565,000 7.3% 

Price greater than 5% and equal to 

or less than 10% 

19 1.5% 8,198,000 1.3% 

Price greater than 10% 0 0.0% 0 0.0% 

 133 10.2% 54,763,000 8.5% 

 

 1,306 100.0% 640,568,790 100.0% 

Based on information available as of January 9, 2003. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-15

In October 2000, El Paso reported accurate numbers but the evidence 

indicates that El Paso desk heads, traders, and management considered 

whether to continue reporting accurate numbers or go back to 

reporting the book bias. The evidence shows that many of the traders, 

desk heads, and managers recommended going back to reporting the 

book bias. The data in Table III-1 strongly suggest that for those 

regions, El Paso did indeed go back to reporting its book bias for the 

period from November 2000 to December 2001. 

El Paso states that it has stopped reporting trading information to the 

Trade Press. 

Staff Reaction to the 

Admissions of False 

Reporting 

Staff expressed concerns about the accuracy of the published price 

indices in its Initial Report. At that time we had no conclusive 

evidence that anyone had actually manipulated the published price 

indices. We argued that, due to the generic problems with the price 

reporting process and problems specific to the California Border gas 

indices, many companies had the incentive and ability to manipulate 

the indices. The admissions (described above) by five significant 

energy trading companies (Dynegy, AEP, Williams, CMS, and El 

Paso) confirm our concerns. Particularly troubling is the common 

theme that because everyone knew that everyone else was 

manipulating the indices by reporting false prices and volumes, it was 

somehow acceptable and even necessary for this to take place. 

Whether the intent was to influence an index in order to favor its 

positions or to somehow offset the false information being provided by 

others, the traders of these companies were deliberately manipulating 

the published price indices by providing false data to the Trade Press. 

In addition, in many cases the heads of the trading desks were aware of 

the manipulations; in some cases, they were orchestrating the 

manipulations. 

Many traders said they were attempting to manipulate the index prices 

in order to offset the attempts at manipulation by others. The AEP 

traders were asked if they ever provided information that they knew in 

advance would be detrimental to their trading position, and each 

indicated they had not. The obvious followup question, which was not 

asked by AEP (or at least not reported by AEP), is whether they ever 

provided information that they knew in advance would be good for 

their trading position. In general, the traders from the companies that 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-16

admitted to providing inaccurate data said they were doing so in order 

to ensure that their positions were reflected in the indices and that they 

were seen as a major player in the markets. In particular, the CFTC has 

concluded that Dynegy was knowingly submitting false information to 

the reporting firms in an attempt to skew the indices to favor its own 

position. Staff concludes that the most likely scenario is that traders 

were manipulating price indices not to help create accurate indices by 

offsetting the inaccuracies of others, but, to the extent possible, to 

move the indices in a direction that favored their positions and create 

the illusion that they were key players at particular locations. 

The responses also indicate that price index manipulation was part of 

the price formation process. The indices are supposed to be based on 

fixed-price trades. Traders manipulated the indices by reporting false 

and inaccurate data on their fixed-price trading activity. Any resulting 

inaccuracy in the published price index fed back into the markets. Staff 

interviews with traders indicate that traders looked at prices in Gas 

Daily every day, just as they watched the activity on EOL. The 

previous day’s index price served as an indicator of the opening 

trading price. In addition, manipulation of the daily indices would feed 

back into the monthly indices because monthly and daily gas are, to 

some extent, substitutes for each other. Moreover, trends in daily 

prices (especially late in the month) provide price information for next 

month’s gas. 

One of the arguments made in defense of the price index reporting 

process and the accuracy of the indices is that, because there are 

entities with the ability and incentive to manipulate the indices in both 

directions, the manipulation is offsetting and therefore the indices are 

accurate. Staff does not find this argument to be persuasive. 

First, there is no reason to conclude that all of the manipulation is 

exactly offset. For example, many of the entities with the most 

influence on the indices are on the same side of the market (that is, 

they want to see the price move in the same direction). Specifically, 

some of the large purchasers of natural gas at the southern California 

border bought gas at fixed prices but sold it at an index price. The 

entities that bought gas at an index price would not be able to 

influence the price, but those that bought at a fixed price would have 

the incentive and ability to increase the index price. 

In fact, six large natural gas buyers (Coral, Duke, Dynegy, Mirant, 

Reliant, and Williams) provided data from 18,320 natural gas 

transactions in California during the period from October 2, 2000 to 

June 22, 2001.8

 During that time the generators’ fixed-price purchases 

 

8

Reishus and Wang Data filed under EL00-95. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-17

were, on average, $0.30/MMBtu less than the published price indices 

for southern California.9

 During the period they paid $46.8 million less 

for their fixed-price purchase than they would have paid if they had 

purchased the gas at the index price. 

Table III-2 shows that in December 2000, a month with extremely 

high and volatile natural gas prices in California, fixed-price purchases 

were, on average, $0.78/MMBtu lower than the published index, 

which is supposed to be based on fixed-price trades. 

Table III-2. December Southern California 

Average of (Spot Price – Published Index) 

 Fixed Price 

Transactions 

Indexed Price 

Transactions 

Buys -0.78 -0.11 

Sells 0.30 -0.22 

Second, it is unrealistic that the traders could use their feel for the 

market (as described by the AEP traders) to predict the direction and 

magnitude of the other traders’ manipulations and calculate a perfectly 

offsetting manipulation of their own. Staff finds that argument to be 

preposterous. As stated by the Trade Press on numerous occasions, the 

only way to ensure accurate index prices is to provide counterparties to 

all trades so they can be cross-checked, thus forcing the trading 

companies to provide accurate data (unless they are colluding) or have 

it thrown out by the Trade Press. 

Third, Staff cannot recommend relying on such a haphazard method—

hoping that the editors of the trade publications can perform some kind 

of alchemy and arrive at accurate prices despite deliberate 

manipulation and no systematic method of reporting the data to the 

Trade Press. Since the Commission has jurisdiction over most of the 

transactions that form the basis for the indices and many Commissionjurisdictional transactions (both gas and electric) are based on the 

indices, it needs to be sure that the published indices are accurate, not 

subject to manipulation, and not serving as a means for price 

manipulation. As the agency of the U.S. Government with the 

statutory obligation to ensure just and reasonable electricity rates, the 

Commission cannot rely on a recipe of offsetting false reports, traders’ 

feel for the market, and editorial judgment (subject to claims of First 

Amendment protection) for accurate price indices. 

The conversations between the editor of Inside FERC and the El Paso 

traders show the inherent flaws in the system. In those conversations 

 

9

In addition, their index-priced transactions were, on average, $0.10/MMBtu lower 

than the published index prices. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-18

(which took place in late 2001, after the California energy crisis), the 

Inside FERC editor is clearly trying to obtain the most accurate data 

possible. This is consistent with Platts’ assertion that it tried to publish 

the most accurate indices possible. However, the fact that the industry 

was not providing counterparties by late 2001 shows that the indices 

were still subject to manipulation. Without counterparty information, 

there was no way for the Trade Press to cross-check for accuracy of 

the reported trades. Platts and other companies that publish indices 

have made improvements in their data-gathering process in the last 

few months. In addition, energy trading companies have expressed a 

willingness to provide complete and accurate data, including 

counterparty information. It is clear to Staff that without counterparty 

information from all parties providing trade data, the published indices 

cannot be counted on to be accurate and free from price manipulation. 

Even with counterparty information, price indices could be 

manipulated through collusion by (1) engaging in wash trading, which, 

as described in Chapter VII, occurred on numerous occasions during 

2000 and 2001; or (2) arranging with another company to submit false 

information in order to provide phony counterparties. Therefore, 

providing counterparty information is a necessary, but not sufficient, 

condition for price indices that are accurate and free from 

manipulation. 

The Commission’s vision is to ensure dependable, affordable energy 

through sustained competitive markets. The basis for using markets to 

set energy prices rather than cost-of-service regulation is the belief that 

competitive markets can more efficiently allocate scarce resources. In 

a properly functioning competitive market, the market price serves to 

allocate resources. The price represents the value of the resource to 

society, reflecting demand and supply conditions. The price sends a 

signal to potential suppliers considering expanding production or 

entering the market; to the financial industry considering whether to 

finance such expansion, and, if so, at what interest rate; to consumers 

making short-term decisions regarding how much energy to consume 

at a given time and long-term decisions such as whether to buy an 

energy-efficient furnace or a gas or electric appliance; and to energyintensive businesses regarding where to locate and which energy 

source to use. The price also signals where infrastructure 

improvements are most critical. A manipulated price sends a false 

price signal and misallocates resources. 

The accuracy and integrity of the market price are especially critical in 

capital-intensive industries such as natural gas and electricity. 

Moreover, as the predominant input choice for new electricity 

generation, the accuracy and integrity of natural gas prices are 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-19

particularly critical. The decision of whether and where to build a 

natural gas-fired generation facility is distorted if the natural gas price 

has been manipulated, which leads to long-term misallocation of 

critical resources and ultimately hurts consumers. Accurate natural gas 

prices that are free from manipulation are the cornerstone of 

competitive natural gas and electricity markets. 

In addition, the published price indices serve as the basis for a huge 

volume of financial derivative trading. Energy companies that serve 

customers use financial markets to hedge the risk in the energy 

industry, which is significant due to inherent price volatility and the 

need to make long-term decisions with little certainty regarding future 

prices. When index prices are manipulated (up or down), financial 

derivative products are not priced properly, market participants lose 

faith in financial markets, and the cost of risk management is 

increased. Ultimately, energy consumers are hurt by the increased 

costs and inability of energy companies to properly manage risk. 

Responses to the October 

22, 2002 Data Request 

On October 22, 2002, Staff sent a data request to the largest natural 

gas marketers and asked a series of questions regarding past reporting 

practices, any internal procedures or controls they may have had in 

place; any changes they have made to those procedures; and any 

investigations they have in progress.10 Staff required those companies 

to investigate whether, in fact, they had misreported data to the Trade 

Press and to provide information on actual trades and reported data so 

that Staff could check the accuracy of those reports. 

This section describes the price reporting practices of seven of the 

largest natural gas marketing companies in the United States. The 

practices for reporting information to the Trade Press varied across 

companies, but there are common themes across companies. In most 

cases, the reporting was done by the trading desks and the traders 

themselves; there was little, if any, internal oversight by management 

or desk heads. In fact, in some cases, the desk heads and management 

were orchestrating the price manipulation. The traders claim they 

provided false data in order to (1) offset the perceived dominance of 

Enron’s input to the process, (2) prove that they could affect the 

published price indices, (3) offset the inaccuracies that other 

 

10Of these ten, three (Dynegy, Williams, and AEP) had already received data 

requests and/or subpoenas from Staff under Docket No. PA02-2 regarding their price 

reporting practices. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-20

companies were reporting, and (4) replicate the prices they perceived 

to be the true range and average of the market. Staff concludes that, at 

least in some cases, the false reporting was done to favor the traders’, 

desks’, or companies’ financial position. In fact, the CFTC has 

concluded that Dynegy “knowingly submitted false information to 

reporting firms in order to skew those indices to Dynegy Marketing.” 

In some cases, the traders understood the process the Trade Press used 

to try to filter out false data and drew on that understanding to 

manipulate the prices by constructing phony counterparties and 

keeping the false data within the range of trading, but only reporting 

numbers that favored their position (i.e., traders that wanted to see a 

low price only reported low trades or inflated volumes on those 

trades). In some cases the traders claim they were unsure of what the 

Trade Press was looking for, so they would report a mix of real trades, 

observed trades, and fabricated trades that reflected their sense of 

market conditions. 

Duke Energy Trading and 

Marketing 

Duke Energy Trading and Marketing (Duke) performed an analysis of 

the correlation between the data reported by its Salt Lake City office 

(West trading desk) to the Trade Press and the actual trade data 

recorded in Duke’s database for its western United States transactions. 

The analysis found that for monthly transactions, 95 percent of the 

reported trades matched the recorded trade on price, 93 percent 

matched on volume, and 92 percent matched on both price and 

volume. For daily transactions reported to the Trade Press, 88 percent 

of the reported trades matched the recorded trade on price, 82 percent 

matched on volume, and 78 percent matched on both price and 

volume. Stated another way, 8 percent of the reported monthly trades 

were inaccurate in terms of price, volume, or both, and 22 percent of 

reported daily trades were inaccurate in terms of price, volume, or 

both. 

Duke interviewed its Salt Lake City traders to try to understand why 

there would be occasions when the recorded trade and the reported 

trade did not match completely. The reasons offered by the traders 

included (1) some small-volume trades were excluded from the 

reporting, (2) some trades occurred after the office’s reporting deadline 

of 1:00 p.m. (Mountain Time), (3) the inadvertent failure to attach a 

list of online trades to the form that was faxed to the Trade Press of 

daily gas indices, (4) a trader’s use of “an eyeball estimate” of a 

weighted average price for transactions that were reported on an 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-21

aggregated basis, and (5) a trader’s reporting of an intracompany trade 

that was normally excluded. Duke concludes that for the vast majority 

of its trades, the Salt Lake City office reported its actual transactions to 

the Trade Press and there was no trader intent to manipulate the 

indices. 

Duke did not perform a similar analysis for its eastern United States 

transactions because “DETM’s Houston office reported to the Trade 

Press data for indicative transactions on broader market information 

than just its transactions.”11 That is, because Duke reported trades that 

it observed in the marketplace, it would not be expected that the 

reported data would correlate highly with recorded transaction data. 

In addition, Duke provided Staff with electronic records of the 

spreadsheets it used to record the range of trades and volume-weighted 

average that it sent to Gas Daily. Examination of these spreadsheets 

shows that Duke calculated its volume-weighted average by taking the 

simple arithmetic average of its high and low trades for the day. 

Therefore, even if the Duke traders were trying to report accurately, 

they were not. Calculating a volume in this manner would not create a 

systematic bias in either direction (that is, tending to systematically 

overstate or understate the volume-weighted average); it provides 

another source of inaccurate price data that is reflected in the 

published price indices.12

Duke did find significant inaccuracies in its reporting by the MidContinent, Gulf, and East trading desks, all located in Houston. Unlike 

traders in Salt Lake City, who reported on actual trades, the Houston 

traders reported their “sense of the market.” The reporting was done by 

the physical gas traders, who generally received the data from 

management and the financial traders. The investigation has found that 

the management and financial traders sometimes biased the reported 

numbers to favor the trading desk’s financial position. 

Duke contends that by providing a “sense of the market,” the traders 

thought they were providing what the Trade Press was looking for. 

Staff finds this argument unpersuasive because, for monthly prices, 

Inside FERC was explicit in its description of what it needed for its 

monthly index—actual fixed-price physical natural gas trades, not a 

“sense of the market” or basis or financial trades. 

 

11Duke response to October 22 Staff Data Request, November 8, 2002. 

12If the distribution of prices was perfectly symmetric about the mean price, 

then the volume-weighted average would be equal to the simple average of the 

high and low trade. There is no reason to believe that would be the case with 

any regularity. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-22

Duke states that most of the senior management in the Houston office, 

including all who participated in the inaccurate reporting, are no 

longer with the company. 

Duke states that its internal review indicates that the process of 

reporting natural gas market data to the Trade Press was informal. 

Duke claims that much of the informality was due to a general lack of 

understanding by Duke regarding what the various publications were 

seeking. Duke states that it has implemented new compliance 

procedures, under the direction of its chief risk officer, to ensure the 

accuracy of the data reported to the Trade Press. 

Coral Energy 

Coral Energy (Coral) interviewed all employees who provided data to 

the Trade Press. Coral has concluded that “the information it provided 

to the Trade Press accurately reflected then current market 

information.” Coral described the type of information each trader (or 

other employee that provided trade data) gave the Trade Press. For 

both daily and monthly data, many Coral traders provided prices and 

volumes of (1) actual trades they had entered into, (2) trades they 

heard had taken place in the market, and (3) trades they had seen on 

trading platforms, including EOL.13

Coral does not address the seemingly obvious problem with reporting 

prices and volumes of trades that traders had “heard about” or “seen on 

electronic trading platforms.” If a trade on EOL was witnessed by 100 

traders, that does not mean the trade happened 100 times. However, if 

the industry practice was to report prices and volumes of trades that 

had been observed or heard about, then trading volumes were 

overstated and those trades made on EOL (the most widely observed 

trading platform) carried undue influence on the published price 

indices. Staff described the influence of EOL in the gas market price 

formation process, especially the Southern California Border daily 

market, in the Initial Report. The fact that traders were reporting trades 

they saw on EOL, sometimes misrepresenting them as their own 

trades, is another way EOL influenced the published indices. As stated 

throughout this chapter, many large traders used the same sort of 

“survey” reporting described by Coral. 

 

13Some Coral traders only provided data on trades they had actually made. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-23

Mirant 

Mirant was the largest natural gas marketer in 2001, as measured by 

total value of trades. Mirant states that prior to September 2002, it had 

no formal or consistent process in place for communicating wholesale 

natural gas transaction data to the Trade Press. Mirant did not have any 

internal policies, spreadsheets, or directives with respect to the form or 

type of information that was being communicated to the Trade Press. 

Natural gas traders provided natural gas transaction information, 

generally over the telephone and through e-mail and facsimile, based 

on questions asked by various Trade Press representatives. 

Mirant’s Office of General Counsel and Office of Internal Audit 

investigated Mirant’s practice of reporting information to the Trade 

Press for the period January 1, 2000 to October 15, 2002. Mirant’s 

investigation team concluded that Mirant traders did not provide data 

that were nonrepresentative of either transactions undertaken by 

Mirant or actual market conditions. 

Mirant did find that traders often reported transactions they had seen in 

the marketplace rather than only reporting its own fixed-price trades, 

but they believed they were reporting in good faith what was 

transpiring in the marketplace. Mirant’s investigation indicates that the 

Trade Publications relied on traders that were active in the market and 

had access to information about the transactions of other players to 

provide prices from observed transactions. Mirant explains that the 

“observed transactions” came from computer screens provided by 

certain brokers and online trading platforms such as EOL and Alltrade. 

Mirant found that one trader deliberately took note of “observed 

transactions” and reported observed prices to Gas Daily. That trader, 

who bought natural gas to serve Mirant’s electric generation plants in 

California, had strong suspicions that the price index was being 

skewed upward by other trading companies that were net sellers of 

natural gas in California. He stated that he reported actual “observed 

transactions” at prices lower than he was transacting to counter the 

artificially high prices he perceived were being reported to push up the 

index price. The trader stated that he told Gas Daily and NGI that their 

published indices appeared to be nonrepresentative of the California 

gas market and that there were several occasions when the Trade Press 

did find reported trades that were not representative of the market and 

excluded those trades from the index calculation. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-24

Since October 2002, Mirant has implemented a formal process for 

reporting information on natural gas transactions to the Trade Press. 

Mirant now directs all calls or contacts from the Trade Press to a 

designated employee in the Risk Control department who is 

responsible for collecting responsive data from Mirant’s actual trading 

records for submission to the publications. Moreover, since October 

2002, records are being kept as to data requested and data submitted. 

BP Energy Company 

BP Energy Company (BP) provided records for trading data reported 

to the Trade Press by fax or e-mail. BP states that during the period in 

question, it provided natural gas prices and transaction data to the 

Trade Press on spreadsheets containing information drawn or 

downloaded directly from the transaction support system. BP had a 

formal system in place for reporting transaction data to the Trade Press 

that included assigning the responsibility for reporting to a single 

trader with oversight and accountability from the trading managers. 

BP could not provide records of the data reported to the daily 

publications over the phone. BP states that any information reported 

over the phone came directly from daily deal sheets. BP’s internal 

price index reporting policy requires all discussions with third-party 

publications to be limited to the designated representative, with the 

trading managers serving as backups. 

 

Reliant 

For daily price reporting (Gas Daily and NGI), Reliant reported daily 

trading by fax to the Trade Press. Each day, traders would pass a daily 

worksheet around the trading floor and one or more traders would 

handwrite information on trading points with which they were 

knowledgeable. Some traders reported pricing for Reliant trades; 

others also reported other trades observed in the markets. At 2:30 p.m. 

each day, a Reliant analyst would fax the worksheet to the Trade Press. 

Reliant states, “[t]he worksheet was not reviewed by a supervisor or 

another employee before it was transmitted.”14

Reliant used different monthly price reporting procedures at its various 

trading desks. It has almost no record of the West desk’s reporting (it 

found a single spreadsheet from the Denver office). However, Reliant 

 

14Reliant response to October 22 Staff Data Request at 4. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-25

was able to locate many of the spreadsheets sent from the East trading 

desks (Southeast and Northeast). 

Reliant’s process for reporting to Inside FERC is particularly 

noteworthy. As described in this Report, Platts’ Inside FERC had a 

standard spreadsheet that it required companies submitting trade data 

to use for reporting bid-week trades for its monthly index. The 

spreadsheet required price, volume, date, and company name to be 

entered for each reported trade. Reliant did not use actual trades to fill 

in the bid-week survey; rather, it used a three-part process to generate 

a set of fictitious trades to enter into the spreadsheet: First, the traders 

agreed to a “consensus” range of trades. Next, an analyst determined 

the midpoint of the consensus range. Finally, “the analyst would 

generate a list of prices—all falling within the consensus range—and 

volumes that arithmetically led to a weighted average at the consensus 

midpoint.”15

Reliant states that it believes the method described above was not 

meant to influence prices; rather, it was intended to provide accurate 

information about market prices. In support of this conclusion, Reliant 

notes that the volumes reported to Inside FERC were often 

substantially lower than Reliant’s actual trade volumes at the reported 

locations. Reliant argues that someone trying to influence the index 

price would tend to overstate volume rather than understate it. 

Reliant compared the reported data to the actual trade data captured in 

its internal computer system. It found that approximately 65 percent of 

the reported midpoints were within 1 percent of the actual midpoint, 

approximately 97 percent were within 5 percent of the actual midpoint, 

and approximately 99 percent were within 10 percent of the midpoint. 

Moreover, the data support Reliant’s claim that it consistently 

underreported the volume of its trades. Of 514 price reports for which 

comparisons could be made, the reported volume was less than the 

actual trade volume in 432 cases (84 percent). In the cases where 

Reliant underreported its volume, the volume reported was 

approximately 15 percent of the actual volume. In 84 cases 

(approximately 16 percent), the reported volume was greater than the 

actual volume—on average, approximately 100 percent above the 

actual volume. Reliant states that the discrepancy in volume was not 

surprising because traders focused on accurate prices rather than 

volumes. 

Staff notes that accurate volumes are a critical part of calculating an 

accurate price index because the indices are volume-weighted 

averages. It is clear from the investigation that one of the ways in 

 

15Reliant response to October 22 Staff Data Request at 8. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-26

which companies tried to manipulate the published price indices was 

by reporting inaccurate volumes—both by overstating volumes of 

trades that favored their position and by understating volumes of trades 

that hurt their position. 

Sempra 

Sempra Energy has three affiliates—Sempra Energy Trading (SET), 

Southern California Gas Company (SoCalGas), and San Diego Gas & 

Electric (SDG&E)—that reported prices to the Trade Press. Each 

entity had different degrees of interaction with the Trade Press and had 

its own reporting procedures. 

SET states that it sent e-mails to Inside FERC and NGI and received 

phone calls from Gas Daily and Btu.16 SET states that no record exists 

of any of the telephone conversations with Gas Daily and Btu. SET 

found only five e-mails of data submitted to Inside FERC and NGI for 

all of 2000 and 2001. SET compared actual trade data with data 

reported to the Trade Press for the small subset of reported trades for 

which it had records, and found no discrepancies. SET states that it has 

learned of some minor discrepancies ($0.01 to $0.02/MMBtu) in the 

data reported to Gas Daily on a few occasions involving an area in the 

Rocky Mountain region.17 SET explains that both Inside FERC and 

NGI requested written transaction information via fax or e-mail for 

their monthly indices. With respect to Gas Daily, there was no formal 

reporting practice. As was the case with other energy trading 

companies, SET employees were sometimes asked by Gas Daily to 

report or comment on general market conditions and/or other trades 

they may have been aware of. SET states that “Responses to such 

requests varied. Some employees refused to comment on trades not 

executed by SET. Others reported their knowledge of various trades in 

the market based on data available on electronic trading platforms 

(such as ICE).”18

SoCalGas unequivocally states that no employee provided inaccurate 

data to the Trade Press. They provided written records of the trades but 

state that there is no way to check on them because they were reported 

over unrecorded phone lines. SoCalGas also states that it is required by 

the California Public Utilities Commission (CPUC) to submit all of its 

trade data to the CPUC and that it provides the same data to the Trade 

Press that it provides to the CPUC. In addition, SoCalGas provided 

 

16Btu Publishing Inc. publishes energy market information and price indices in 

its publications: Btu Weekly, Btu’s Daily Gas Wire, and Btu’s Midday Report. 

17SET response to October 22 Staff Data Request at 2. 

18SET response to October 22 Staff Data Request at 3. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-27

Staff with spreadsheets identifying all spot market transactions for 

2000 and 2001; the spreadsheets indicated if the transaction was a 

purchase or sale, price, volume, and counterparty. These data were the 

same as the data submitted to the CPUC. 

SDG&E states that it was not a significant natural gas trader and, as 

such, its employees provided prices and volumes to the Trade Press on 

a limited number of occasions. SDG&E states that no employee 

provided any inaccurate information to any entity publishing price 

indices. SDG&E further states that as a regulated California public 

utility, it provides monthly reports to the CPUC’s Energy Division and 

to the CPUC’s Office of Ratepayer Advocates, providing details of all 

its physical and financial natural gas transactions. 

Aquila Merchant Services 

Aquila Merchant Services (AMS) states that it had three trading desks: 

West, East, and Mid-Continent. It reported daily trading data to Gas 

Daily and monthly data to Inside FERC and NGI; daily trading data 

were reported by fax. Each day traders would pass a form (the Aquila 

Energy Marketing Gas Daily Pricing Log) around the trading floor and 

one or more traders would handwrite information on trading points 

with which they were knowledgeable. AMS would report the range of 

trades, midpoint, and volume. AMS states that although the desk head 

was ultimately responsible for the information sent to Gas Daily, it 

appears that any trader could enter data onto the form. Interviews with 

traders indicate that some traders provided only actual AMS trades 

while others reported a combination of trades they saw on electronic 

platforms (such as EOL) and actual AMS trades. Traders indicate that 

there was some uncertainty over the specific data Gas Daily wanted, 

that is, whether Gas Daily wanted only actual trades or more of a 

market survey. 

For monthly reporting, AMS employees reported trade data by e-mail 

on a spreadsheet that was stored on a shared drive. As with daily 

reporting, although the desk head was ultimately responsible for the 

information sent to Inside FERC and NGI, it appears that any trader 

could enter data onto the form. In compliance with Staff’s data 

request, AMS analyzed the accuracy of the reported monthly prices by 

comparing the actual trade data with the reported trade data. AMS 

found that the data reported by the West desk were accurate, but the 

data reported by the East and Mid-Continent desks showed 

discrepancies for January, February, March, April, and June 2000. In 

one case, a trader stated that the desk head provided a range of prices 

that he knew were not based on real prices and a volume-weighted 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-28

average price that he knew was not accurate, and gave instructions to 

fill in fictitious numbers within the false range on the spreadsheet to 

arrive at the false weighted average. The trader stated that this practice 

stopped after October 2000, when AMS instituted a practice of 

reporting counterparties for every trade and only reporting fixed-price 

trades. 

The evidence suggests that the attempt at price manipulation was not 

done specifically to offset the misreporting of other companies, but 

there was a general sense among the traders and desk heads that other 

companies (including Enron) were attempting to manipulate the 

published indices to their financial advantage and hurting AMS. One 

trader described it as a Prisoners’ Dilemma,19 that is, given what the 

other large trading companies were doing (reporting false data to favor 

their positions), his best response was to report false prices even 

though everyone would be better off with accurate price indices. 

AMS states it had concerns with the price reporting methodology and 

it perceived that others were manipulating the indices. Through 

interviews with traders, desk heads, and former AMS managers, it 

found specific accounts of AMS employees contacting the Trade Press 

to question the accuracy of the published indices when AMS 

employees did not believe the indices were representative of market 

conditions. AMS provided copies of letters sent by its General 

Manager to Financial Times Energy and Inside FERC regarding the 

methodology used to compile its indices and advocated accepting only 

trade data from companies that have agreed to be audited. 

In August 2002, AMS announced that it was shutting down its 

wholesale marketing and trading operations. By the end of the third 

quarter of 2002, AMS had eliminated most of its wholesale marketing 

and trading business, including market making activity and speculative 

trading. By the end of the fourth quarter of 2002, AMS had unwound 

almost all of its energy trading positions. AMS states that it has 

eliminated most of its positions in merchant operations and most of its 

employees, and no longer reports trade information to energy industry 

publications such as Gas Daily, Inside FERC, or NGI. 

 

19In the Prisoners’ Dilemma, two prisoners must decide separately whether to 

confess to a crime; if only one prisoner confesses, he will receive a lighter sentence 

and his accomplice will receive a heavier one, but if neither confesses, sentences will 

be lighter than if both confess. The individual incentives faced by both prisoners 

force them to confess, even though they would both be better off if they did not. The 

outcome (mutual defection) is an example of a Nash Equilibrium in game theory. 

See, for example, Robert S. Pindyck and Daniel Rubinfeld, Microeconomics, 5th 

edition, pp. 442-444. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-29

 

Staff Reaction to Responses 

to the October 22, 2002 Data 

Request 

The answers to the questions in the October 22, 2002 Data Request 

show that the industry lacked systematic reporting procedures and 

internal verification processes.20 The responses also show that the 

price manipulation goes beyond the five companies that have admitted 

to such behavior. 

As noted above, most of the largest natural gas marketing companies 

in the country had no formal process for reporting trade data to the 

publishers of the price indices; the process was left to the trading desks 

and the traders themselves. Traders from all companies describe a 

typical trading day as hectic, pressure packed, and frenetic. One of 

their many tasks was to report trading data to the Trade Press; this was 

viewed as bothersome but necessary. Often it was a job given to the 

newest employee. Many companies report passing around a form or 

using a spreadsheet on a shared drive. The last person who filled out 

the form or spreadsheet may have been required to total the numbers 

and send them to the Trade Press. There was nothing to stop a trader 

from changing the numbers someone else had entered. In other cases, 

traders took an oral “survey” to get a sense of where the market was 

trading. Sometimes they represented it to the Trade Press as an actual 

survey, but in other cases they made up trades to average out to a 

number that was consistent with this “survey.” 

Although Inside FERC did have a spreadsheet and requested data on 

fixed-price deals transacted during bid week only, it is clear that the 

companies were reporting a combination of fixed-price deals during 

bid week, trades observed on EOL, and trades they made up to reach a 

predetermined average. 

The process for reporting daily prices was more chaotic than the 

process for the monthly indices. Again, the responses show that traders 

reported some combination of actual trades, trades they observed, and 

trades they made up. Some traders reported a range of prices and some 

reported an average. Sometimes the average was volume weighted; at 

 

20BP Energy is a notable exception. It is clear from BP’s response to the Staff data 

request that it recognized the influence a significant trader such as itself could have 

on the published indices. BP put internal controls in place to ensure the accuracy of 

the reported data and a employed a system of accountability for the trading desk 

heads. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-30

other times it was the simple average of the high and low trades. Some 

traders received phone calls, some called the Trade Press, and some 

faxed prices and volumes. Staff inspection of the faxes shows that 

there was no standardization of the data reported to the Trade Press. In 

some cases volumes and average prices were reported, some had 

individual trades, some showed basis differentials, and some were 

financial rather than physical deals. Because most of the reporting was 

done by phone, there are significant barriers to finding out what the 

traders actually reported to the Trade Press. As with Inside FERC, the 

editors of Gas Daily assert First Amendment protection, so there is no 

way to ascertain what they were told and their awareness of the extent 

of the manipulation. Moreover, the companies themselves were unable 

to re-create their daily reporting because (1) it was done by phone and 

the phone calls were not always recorded (even if they were recorded, 

it would take thousands of hours to listen to the recorded calls) and (2) 

the Trade Press denied companies’ requests for their own data, citing 

confidentiality and First Amendment protection. 

In short, the responses indicate that the reported price indices were 

based on data that were confusing, inaccurate, misleading, and often 

false. Staff concludes that an accurate index could not have resulted 

from the data that were reported. In addition, because the Trade Press 

has not revealed their data, there is no way to verify the accuracy of 

the reported indices by comparing them with the data reported to the 

Trade Press. 

Staff Attempts To Verify the 

Accuracy of the Reported 

Indices 

As part of the investigation, Staff attempted to verify the accuracy of 

the reported price indices; however, there have been significant 

barriers to this process. First, in many cases the companies cannot 

reproduce the data they reported to the Trade Press for the reasons 

described above: daily reporting was done by phone, often on 

unrecorded lines; many traders reported their own trades along with 

those they observed in the market; and records of the reported data 

were not maintained because there was no formal process for reporting 

the data. In addition, the Trade Press has not revealed the data used to 

calculate the indices. 

One of the issues that became apparent to Staff while investigating 

Enron and other energy traders is that they lack many business records 

that are essential when investigating allegations regarding trading 

activities. Because the companies have argued that their trading 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-31

activities are not jurisdictional to FERC, CFTC, or SEC, many fail to 

keep records that would be required of a regulated company. For 

example, maintenance of phone tape recordings can be haphazard at 

these companies. Staff found evidence indicating that Enron had 

received a legal opinion finding that their 4-month tape retention 

policy was not in compliance with FERC regulations. During the same 

time that Enron received this finding, they were reducing their 

retention to 30 days. Although the retention of phone tapes in the 

power industry is an accepted practice, the length of retention varies. 

Specifically, the lack of record keeping, especially recorded telephone 

conversations, made it difficult and, in some cases, impossible to 

verify the data provided by the companies to the Trade Press. 

As described earlier in this chapter, Staff analyzed the trading data of 

six major gas purchasers in California and compared them to the 

published price indices. The analysis uses data submitted under Docket 

No. EL00-95 by David Reishus and Patrick Wang of Lexecon Inc. on 

behalf of five companies involved in that proceeding (Duke, Dynegy, 

Mirant, Reliant, and Williams). The database they used included spot 

transactions from six companies: Coral, Duke, Dynegy, Mirant, 

Reliant, and Williams. Staff found that for those six companies during 

that period, their fixed-price purchases were systematically lower than 

the published index prices (which are supposed to be based on that 

type of transaction only).21

Industrywide Reporting 

Issues 

As described in the Initial Report, the industry relies on both daily and 

monthly natural gas price indices. The monthly price indices are based 

on fixed-price transactions occurring during bid week. During the 

course of the investigation, it became clear to Staff that transactions 

occurring during bid week do not give an accurate picture of the 

monthly natural gas trading activity. A number of large traders (e.g., 

Dynegy, AEP, and Williams) stated that they did very little fixed-price 

trading during bid week. They stated that they mainly traded indexed 

contracts or small fixed-price deals designed to fine tune their physical 

and/or financial positions for the month. Data provided from the large 

natural gas traders and marketers confirm this position. In fact, traders 

said that one of the reasons they fabricated the prices and volumes they 

provided to the Trade Press was that they had very few trades during 

bid week and they wanted to reflect their actual trading activity for the 

month. Another problem with reporting bid-week trades only is that 

 

21See Table III-2 on page III-17. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-32

the market is quite thin during this period; that is, there are fewer 

buyers and sellers (at least for fixed-price deals). Therefore, even if 

prices for trades made during bid week were reported accurately, those 

prices do not necessarily reflect competitive market prices. 

The Testimony of Michele 

Markey 

On November 18, 2002, Michele Markey testified before the State of 

California Senate Select Committee to Investigate Price Manipulation 

of the Wholesale Energy Market. According to her testimony, from 

May 1998 to September 2001 Ms. Markey was in charge of the gas 

price and electric price teams that gathered information from the 

industry for publishing the price indices in Gas Daily and Megawatt 

Daily. From her experience as a trader and her work at Financial 

Times Energy and Platts,22 Ms. Markey described the energy trading 

process, the data gathering process at the daily and monthly 

publications, and the perception in the marketplace of the published 

price indices; she also gave examples of how an index could be 

manipulated. When asked by Senator Dunn if, in her opinion, it was 

common practice in the industry to exaggerate the prices reported to 

the indices, she replied: “It was common industry knowledge that 

exaggeration was part of the process.”23

One of the subjects Ms. Markey addressed was that traders understood 

that if the prices they reported were too far out of line with real prices, 

they would be thrown out by the editors of the price indices. 

Therefore, traders would report trades that favored their positions but 

were within the range of actual trading. She explained that because the 

indices were weighted averages, traders could manipulate the index by 

reporting inflated volumes at prices that favored their positions: 

Common practice was to exaggerate your transactions to the 

price reporters, report more volume, report a higher price than 

that was actually transacted. You stretched your price in favor 

of what the company’s position was, or don’t report at all, 

because you would know whether or not your indices—your 

volume and price could in fact affect the index.24

Ms. Markey also discussed a proposal by Enron for Gas Daily to 

create an electronic platform price index. The index was designed to 

 

22Ms. Markey also worked as a West desk trader for Reliant prior to her employment 

with Financial Times and Platts. At the time it was called Noram Energy Services. 

23Markey testimony at 13.

24Markey testimony at 15. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-33

capture all trading on electronic platforms, but ultimately captured 

only Enron. She testified that: 

In effect, Enron gave us the methodology and dictated to us 

how that price index was going to be calculated. And we set it 

up basically at their request.25

In the summer of 2001, Ms. Markey proposed that Gas Daily (owned 

by Financial Times Energy at that time) audit the data from EOL in 

order to ensure its accuracy. She stated that a number of energy traders 

complained that Enron was manipulating prices through EOL. She 

arranged for Price-Waterhouse-Cooper to audit the data and the 

contract was ready to be signed; however, in August 2001, the plan 

was abandoned when Platts purchased Gas Daily. Therefore, there was 

no audit of the Enron data. 

On November 19, 2002, the president of Platts, Harry Sachinis, issued 

a statement in response to Ms. Markey’s claims. Mr. Sachinis 

explained why Platts had rejected her proposal to publish an EOL 

price index and to audit the data from EOL: 

Michele Markey, who worked for Platts for only six months, 

implied that we quashed a suggestion to audit questionable 

trading data supplied by Enron because Enron was a Platts 

customer. This is completely false. In fact, Platts chose not to 

pursue Ms. Markey’s auditing proposal because publishing an 

index based on Enron Online trading data would have little if 

any value to subscribers. Platts had previously declined 

requests by Enron to publish such an index. Platts believes 

that an index based on a single company’s trades would be 

unreliable and subject to manipulation, whether audited or 

not.26

The Effect of Enron and EOL 

on the Published Price 

Indices 

The issues discussed by Ms. Markey are related to some of the 

concerns raised by Staff in the Initial Report regarding the influence of 

EOL on the published price indices. As stated in the Initial Report, 

EOL was a significant source of price discovery in the natural gas 

markets. The responses to the data request confirm that many traders 

looked at EOL to observe market conditions. In fact, many traders 

 

25Markey testimony at 39. 

26Platts response to Markey, November 19, 2002. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-34

actually reported trades they observed on EOL to the Trade Press; 

some of those traders misrepresented those trades as transactions they 

had made themselves. As described in this Report, EOL was a one-tomany trading platform, i.e., the Enron market maker was on one side 

of every trade done on EOL. The market maker established the bid and 

ask prices and profited from the spread between the two. In addition, 

the market maker had information superior to the rest of the market 

and had the ability to influence the price. By posting the bid and ask 

prices for a particular location at a given price, an Enron trader would 

have a greater likelihood of affecting the index price at any point 

traded on EOL than any other single trader. Thus, trades made on EOL 

could be fed into a particular index over and over, as other traders 

were reporting what they observed on EOL to the Trade Press. Some 

of the traders that attempted to manipulate the indices said that they 

were doing so in order to offset Enron’s perceived dominance at 

particular trading points, particularly at Topock on the California 

border. 

Ms. Markey proposed publishing an EOL price index and auditing 

Enron’s reporting practices. As argued by Platts’ president Harry 

Sachinis: 

Platts chose not to pursue Ms. Markey’s auditing proposal 

because publishing an index based on EnronOnline trading 

data would have little if any value to subscribers. Platts had 

previously declined requests by Enron to publish such an 

index. Platts believes that an index based on a single 

company’s trades would be unreliable and subject to 

manipulation, whether audited or not. 

Staff agrees with Mr. Sachinis’s conclusion that an index based on a 

single company’s trades would be unreliable and subject to 

manipulation. The facts uncovered in this investigation indicate that 

EOL had an undue influence on the published indices, especially the 

SoCal Topock Gas Daily Index. Those facts are as follows: 

1. A large percentage of the legitimate trading for SoCal Topock took 

place on EOL. 

2. Much of the trading for SoCal Topock on EOL was between Enron 

and one counterparty, Reliant, which had a “netting arrangement” 

with Enron; this arrangement created the incentive to “churn” (see 

Chapter II) natural gas on EOL. Only Enron and the Reliant trader 

knew of the netting arrangement. 

3. Many traders reported trades they observed on EOL. Some traders 

misrepresented those trades as their own transactions. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-35

4. Traders used EOL for price discovery, so the price of off-EOL 

trades was influenced by EOL. 

SoCal Topock: EnronOnline and Gas Daily Index Value

$0

$10

$20

$30

$40

$50

$60

$70

10/1/2000 11/20/2000 1/9/2001 2/28/2001 4/19/2001 6/8/2001 7/28/2001

Date

Price

($/MMBtu)

EOL Mean Gas Daily Index

As shown in Figure III-1, the Gas Daily price almost perfectly tracks 

the EOL price. In the Initial Report, Staff focused on one trading day, 

January 31, 2001. On that day, total trading volume at southern 

California Topock reported to Gas Daily was 6,766,000 MMBtu, 

which was the busiest trading point for that day. The total volume on 

EOL for next-day Topock gas for the day was 2,240,000 MMBtu. At 

the time of the Initial Report, Staff did not know the extent to which 

the reporting of trading volume was manipulated by the traders. The 

total volume of trading on EOL for the day (2,240,000 MMBtu) is 

actual trading verified by Staff. The total volume reported by Gas 

Daily (6,766,000 MMBtu) cannot be verified because Gas Daily has 

not revealed its data. Moreover, as described above, most companies 

spoke to Gas Daily’s editors over the phone and did not keep records 

of what they reported. Staff suspects that of the 6,766,000 MMBtu 

reported by Gas Daily, much of it was based on trades observed on 

EOL in addition to the actual trades made on EOL. Finally, as noted in 

the Initial Report and discussed in Chapter II, more that 75 percent of 

the trading on EOL that day was with one trader from Reliant. Thus, 

the volume reported and the observed activity on EOL give the illusion 

of a much more liquid market than was actually present. 

Figure III-1 

SoCal Topock: EnronOnline and Gas Daily Index Value 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-36

As described in detail in Chapter II, the anomalous trading behavior on 

EOL would influence the index price because the index price was a 

volume-weighted average.27 That is, even if the price returned to 

where it was before a flurry of buying and selling (churning), the 

volume-weighted average would increase because all of the buys and 

sells occurring during the churning were taking place at a higher price. 

The fact that numerous market participants were reporting what they 

saw on EOL only intensifies this effect. 

In addition, as described in detail in Chapter IX, Staff has identified a 

case in which Enron traders used EOL to manipulate the Henry Hub 

market price. In the July 19, 2001 manipulation, the Enron market 

maker aggressively bought natural gas at Henry Hub to drive up the 

price, then aggressively sold the gas, driving the price back down, 

while his partners in the scheme made huge profits in financial 

derivative products by selling short when the price was rising, 

knowing that it would soon fall. Even though the price returned to its 

premanipulation level once the scheme was complete, the 

manipulation affected the index price because it is a volume-weighted 

average. The manipulation induced a price run-up and an ensuing fall. 

The trades that took place during the manipulation were all above the 

pre- and postmanipulation price level, thus bringing up the average. 

Again, the fact that numerous market participants were reporting what 

they saw on EOL intensified this effect. 

The index prices also fed back into southern California natural gas 

market performance through the gas imbalance penalties on the 

SoCalGas system. As described in Chapter II, the penalties for 

imbalances on the SoCalGas system were 150 percent of the highest 

daily border price index at the Southern California Border for the 

month the imbalance is created. The highest daily border price index is 

an average of the prices from NGI’s “Daily Gas Price Index—

Southern California Average” and the Gas Daily “Daily Price 

Survey—SoCal Large Packages Midpoint Price.” Therefore, a higher 

index price would increase the imbalance penalty, which would in turn 

increase the price buyers were willing to pay for gas in order to avoid 

the penalty. 

Staff concludes that all of the concerns expressed in the Initial Report 

have been confirmed. These concerns include the following: 

 

27See Chapter II, Reliant’s Churning Raised the Index Prices, page II-30. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-37

♦ The Commission cannot independently verify the published price 

data. 

♦ Undetected errors may exist because trade publications reporting 

spot and forward prices do not employ statistically valid sampling 

procedures or a systematic, formal verification procedure. 

♦ Market participants have significant incentives to manipulate spot 

market prices reported to the reporting firms because natural gas is 

the fuel input for the electricity generators that set the market price 

in California. 

♦ Wash trades may have an adverse effect on reported price data. 

♦ EOL was a significant source of price discovery and formation and 

was potentially susceptible to manipulation by market participants, 

which could affect the published price indices. 

Moreover, systematic attempts to manipulate the published price 

indices by various significant market participants occurred for at least 

4 years. Because of these events, some companies have stopped 

reporting trading data to the Trade Press;28 many companies have left 

the trading business;29 Dynegy settled with the CFTC for attempted 

price manipulation and other violations of the Commodity Futures 

Trading Act; some traders have been indicted on Federal criminal 

charges;30 and AEP has been the subject of a class-action lawsuit. 

On the positive side, there has been a movement within the industry to 

fundamentally reform the price reporting process. Suggestions for 

reform and tangible reforms have come from market participants, risk 

officers, the trade publications themselves, new entrants into the price 

reporting business, government agencies, consumer groups, and 

others. 

On January 15, 2003, Commission Staff from the Office of Market 

Oversight and Investigation (OMOI) reported concerns regarding price 

index formation to the Commission at its public meeting. Staff 

explained the Commission’s interest in price index formation, 

reviewed the public evidence that raised questions about it, defined the 

high-level criteria that are important to developing trustworthy price 

information in the future, and proposed some next steps. 

OMOI Staff proposed that in the future, the Commission should 

require that natural gas price indices meet certain minimum 

requirements before natural gas pipelines are permitted to use the 

 

28For example, BP Energy, El Paso, Reliant, Williams, Constellation, and PP&L. 

29For example, Aquila Marketing Services and CMS. 

30See El Paso and Dynegy. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-38

indices in new tariffs or for other new regulatory purposes. Staff 

proposed that evidence for these new filings would need to be 

presented and reviewed to ensure that any referenced price index 

meets minimum index formation standards. In particular, the index 

would need to accurately reflect the market. For approval, a new tariff 

containing a reference to an index would need to demonstrate: 

1. Confidence in the accuracy of price reporting—that is, the ability 

to verify that reporting is for deals actually done, not simply 

aggregate options. 

2. Adequacy of coverage—that is, the ability to ensure the collection 

of adequate information to represent prices across the relevant 

marketplace. 

3. Information about market liquidity or some insight into how much 

trading is going on a particular point in order to generate warnings 

when markets are thin and confidence when they are liquid. 

4. Verifiability—that is, the ability to ensure integrity of the process 

through independent review by a trustworthy third party 

(preferably not a government entity).31

Reform of the Price 

Reporting Process 

Company Changes 

Most of the companies involved in natural gas trading and marketing 

have implemented or are in the process of implementing new 

procedures for reporting trading information to the Trade Press. 

Specifically, many companies are moving the data reporting process 

away from the trading desks to the risk management office. In 

addition, companies are using their IT systems to capture the relevant 

data and send it directly to the risk management office. For example, 

Duke’s new policy is as follows: 

Transactions are captured in DETM’s trading systems. 

System queries have been developed to extract the relevant 

third-party physical transactions from the source systems and 

generate a report. The report contains the location, price, and 

volume for each transaction. The mid-office receives the 

electronic report and reviews the data. The transactions that 

are submitted to the publications are validated through a 

combination of confirmation and trade validation control 

 

31FERC OMOI Staff Report. 2003 Natural Gas Market Assessment. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-39

procedures. These procedures will ensure that only 

information about actual transactions entered into with third 

parties will be provided to the Trade Press publications.32

As noted above, many other trading companies (including Mirant, 

AEP, and Dynegy) are adopting similar procedures. Staff finds that the 

revised process for reporting the relevant trade data to the Trade Press 

is a significant improvement that gives credibility to the data and that 

it is in stark contrast to the nearly universally haphazard reporting that 

took place in the past. 

In addition, many companies (including PP&L, BP Energy, El Paso, 

Reliant, Williams, CMS, and Constellation) have stopped reporting 

trading data to the Trade Press. This is an understandable reaction 

given the chaos in the industry and the legal issues facing firms that 

have already admitted to providing false information and those that are 

still investigating or are the subject of investigations as to whether they 

provided false information. Because the indices for commercial 

transactions are very important, procedures must be put in place to 

ensure the accuracy of the indices and to encourage (or require) all 

market participants to provide complete and accurate data. Staff 

recommends that a process for establishing standards for price 

reporting be established by the Commission, with input and 

cooperation from the energy industry and the price reporting firms. In 

addition, other government agencies (such as the CFTC and the 

Energy Information Administration) should be involved in the process. 

Significant progress has been made in this area since the issue 

regarding the accuracy of the reported indices became a subject of this 

investigation. 

Proposal of the Committee of Chief Risk Officers 

As described above, in many cases the reporting function is being 

moved to the companies’ risk management offices. On November 19, 

2002, the Committee of Chief Risk Officers (CCRO) (representing 31 

energy companies) announced that it is examining how companies 

submit price data and what type of data are submitted and that it hopes 

to develop a “transparent and robust methodology” that will maintain 

confidentiality. 

On December 4, 2002, the CCRO met with the publishers of energy 

price indices to discuss the attributes of credible market price indices 

 

32Letter to Donald Gelinas, Associate Director, Office of Markets, Tariffs, and 

Rates, from Mark Perlis, Counsel to Duke Energy Trading and Marketing 

L.L.C., under Docket No. PA02-2, November 8, 2002. 
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Docket No. PA02-2-000 Price Manipulation in Western Markets III-40

for energy transactions. The forum was open to all companies 

currently publishing indices for the North American energy market. 

The CCRO stated that “[l]eaders of the Committee’s Market Price 

Indices Working Group embarked on this task amid questions about 

how price indices for natural gas and electricity transactions have 

been, and are being, tabulated.” The CCRO further stated that it 

“intends to consider information and points of view provided by the 

publishers’ representatives to help produce draft recommendations that 

will lead to credible, sustainable price indices in the coming weeks.”33

On February 27, 2003, the CCRO released its Best Practices for 

Energy Price Indices white paper. The CCRO white paper includes 

recommendations for data gathering and submission procedures, index 

construction processes and methodology, and necessary contractual 

arrangements to facilitate the recommended changes on the part of 

both the companies supplying market information and any entity 

publishing energy price indices. The white paper also recommends a 

formal auditing process for both the energy companies providing data 

and the companies publishing price indices. 

Data Gathering and Submission 

The CCRO recommends that data providers supply index developers 

with these and other data points about each trade, every day they trade: 

♦ Buy or sell indicator. 

♦ Volume of energy involved. 

♦ Flow date(s) of the energy transaction. 

♦ Location of delivery points. 

♦ Price. 

♦ Any exchange or clearinghouse involved. 

♦ Date the transaction was executed. 

♦ Counterparty. 

Index Construction Process and Methodology 

The CCRO has the following recommendations for index publications: 

♦ Index developers should implement robust IT and data security 

protections against data misuse by employees. 

♦ Index developers should publish the index methodology, including 

defining (1) a sufficient sample size for normal creation of an 

 

33December 2, 2002 press release: Committee of Chief Risk Officers Plans Forum to 

Discuss Energy Price Indices. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-41

index and (2) the process for determining an index value where 

there are insufficient data. 

♦ Index developers should ensure that the “strictest standards of 

care” will be maintained over commercially sensitive data. The 

paper also recommends that index developers audit their processes 

annually. 

Contractual Arrangements 

The CCRO recommends that before the information described above 

is provided, contracts should be drawn up and amended between 

counterparties to protect the confidentiality of the data. The CCRO 

encouraged data providers and index developers to sign an agreement 

that, among other things: 

♦ Commits each party to a specific data-reporting protocol. 

♦ Protects the confidentiality of the data. 

♦ Prohibits the use of data beyond constructing an index. 

The CCRO recommended that counterparty information should be 

submitted only after: 

♦ Each individual with access to the data at the index developer signs 

a clear-cut, enforceable confidentiality agreement. 

♦ Any index produced by a publishing organization is separated from 

any news-gathering operations by a verifiable and auditable 

“Chinese wall.” 

Auditing Process 

The white paper recommends a formal auditing process for both the 

energy companies providing data and the companies publishing price 

indices. 

The CCRO recommends that independent audits be conducted by each 

company publishing indices at its expense at least annually to 

determine the following: 

♦ The data are properly collected and stored in compliance with all 

contractual arrangements with data providers, including 

confidentiality arrangements. Specifically, the data are properly 

protected from release and misuse at all levels. 

♦ The methodology established and published by the index developer 

is the same as that used to calculate and publish the actual index. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-42

♦ The methodology established and published by the index developer 

satisfies the attribute of robustness as defined by the index 

developer in accordance with the principles in this white paper. 

♦ Periodic tests are conducted to verify that the process used to 

derive published indices is accurate, objective, and reliable. 

The CCRO also recommends a formal auditing procedure for the 

companies submitting data for index publication: 

An independent (internal or external) audit group should 

review the data gathering and submission process at least 

annually, verifying the proper implementation of and 

adherence to the data gathering and submission process that 

the company has established. This audit should be conducted 

at the expense of the data provider by a qualified individual, 

i.e., Certified Public Accountant or Certified Internal Auditor. 

The pass/fail results of the audit should be made available to 

the index developers upon request. In the event of a failed 

audit, the data provider should be able to reaudit once 

appropriate process changes are made. 

Staff commends the CCRO on its efforts to reform the index price 

reporting process. Although the CCRO white paper is a 

recommendation for best practices and not a binding commitment by 

its member companies, it addresses the fundamental problems in the 

process and provides feasible solutions. The necessary data to compile 

an accurate and reliable index identified by the CCRO are nearly 

identical to those proposed by Staff later in this chapter.34 

The CCRO paper has directly addressed the critical pieces of 

information for ensuring an accurate index: providing the counterparty 

and buy/sell information for every trade. The paper recognizes the 

commercial sensitivity of such information, but proposes amending 

existing energy contracts to allow for its provision, provided the 

confidentiality is preserved by the index publishers through explicit 

contracts. As discussed throughout this chapter, without the ability to 

cross-check reported prices and volumes, the published indices will 

not be reliable. As noted by Platts in its February 10, 2003 call to 

action: 

 

34It is Staff’s position that one critical piece of information missing from the CCRO 

proposal is the time stamp of when the transaction was made. Staff understands this 

to be an IT issue that could be worked out. The time stamp would further aid in 

cross-checking transactions and assessing whether an outlier should be rejected 

(since prices may move significantly within a day of trading) when calculating a 

price index. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-43

Information on counterparties, buy/sell indicators and time 

stamps is critical to the process of verifying data. This 

information will help Platts in its efforts to confirm such data 

characteristics as completeness (by enabling publishers to 

detect a provider’s omission of certain deals) and accuracy, 

and it will serve as a check against double counting. In fact, 

counterparty information is one of the best means for 

publishers to identify inaccurate or, indeed, fictional 

transactions. The industry should make the provision of 

counterparty names a top priority and resolve confidentiality 

or other issues that some companies say prevent them from 

providing that information. 

It is Staff’s position that if both the index publisher and all of the 

energy companies providing data followed the best practices described 

in the CCRO paper, the resulting index would meet the standards 

proposed by Staff for an index that can be used for Commissionjurisdictional transactions. Staff recognizes that the CCRO cannot, nor 

does it attempt to, make its recommendations mandatory. Staff 

commends the CCRO on putting forth a serious proposal that is 

already part of the discussion on fixing the energy indices and will 

continue to be part of the solution. As discussed in the “Staff 

Recommendation to the Commission,” many of the best practices 

described by the CCRO are the same as those Staff recommends be 

made mandatory for Commission-jurisdictional companies. 

Changes by the Trade Press in the Price Index Methodologies 

In the Initial Report, Staff noted that the Trade Press announced 

changes to its data gathering procedures in order to improve the 

accuracy of the reported indices. In addition, the Trade Press has 

continued with those efforts since the Initial Report was issued. 

Platts 

In the Initial Report, Staff noted that Platts had proposed refinements 

to its power market methodology.35 On September 2, 2002, Platts 

proposed refinements to its natural gas price index methodology. 

Those changes included the following: 

To improve the quality of information it receives for each transaction, 

Platts will be asking market participants to provide quantity and price, 

the name of the counterparty, whether the reporting company was the 

 

35Initial Report at p. 37 (fn 44). 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-44

buyer or seller, and the time at which the transaction was completed. 

Currently, Platts obtains these data from some (but not all) market 

participants. Platts also is considering other refinements to increase the 

quality of its gas pricing data and welcomes industry input before any 

changes are made. Changes under consideration include the following: 

♦ Using physical basis transactions in its monthly surveys. Basis 

deals transacted during the last 3 days of trading of the near-month 

NYMEX gas futures contract would be included with fixed-price 

physical deals. Among other things, Platts solicits input on whether 

physical basis transactions generally are compatible with fixedprice deals in some regional markets but not others. 

♦ Requiring the signature of a senior company official to verify the 

accuracy of price data submitted to Platts. 

♦ Obtaining data from back offices rather than trading desks.36 

On October 28, 2002, Platts announced that it was adopting steps to 

strengthen the price survey of the U.S. electricity markets and that it 

was making similar changes to its methodology for natural gas indexes 

and assessments.37

On February 10, 2003, Platts published a statement on its views of the 

necessary reforms in the price index reporting process, Market 

Reporting in North American Natural Gas and Electricity—

Recommendations for Restoring Trust and Transparency: A Call To 

Action. Platts made the following recommendations: 

♦ Market participants should provide data from a central source in a 

mid- or back-office operation that would have the responsibility 

for confirming the accuracy and completeness of the data provided 

to price-reporting organizations such as Platts. 

♦ Market participants should submit detailed transactional level 

data—not aggregated data. 

♦ Market participants should provide counterparty information for 

each transaction reported. The naming of counterparties offers an 

important check for verifying the completeness and accuracy of 

trade data. 

♦ Market participants should provide written certification from a 

senior level official, such as a chief risk officer, attesting to the 

accuracy and completeness of the information reported to 

publishers. This certification would be renewed periodically. 

 

36Gas Daily, Proposed Refinements To US Gas Price Methodology (September 

2, 2002). 

37Megawatt Daily, October 28, 2002.
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-45

♦ Market participants should understand that these measures and 

others noted below can only serve to re-establish confidence and 

credibility in price reporting on the North American gas and 

electricity markets. 

Platts described the high-quality data that it is seeking from market 

participants in order to ensure accurate price indices: 

 

In North America, Platts is asking electricity market 

participants to provide for each transaction the delivery 

location, trade date, start flow date, end flow date, peak or 

off-peak, physical or financial, price ($/MWh), volume 

(MW), transaction time, buy or sell indicator, and 

counterparty. In the gas market, Platts asks market 

participants to provide for each transaction the delivery 

location, the trade date, flow date, price ($/MMBtu), volume 

(Mcf), and counterparty, and to state whether the deal is 

fixed-price physical or basis and whether it is a buy or sell 

transaction.38

Platts further described the need for critical pieces of information such 

as counterparties to each trade: 

Information on counterparties, buy/sell indicators and time 

stamps is critical to the process of verifying data. This 

information will help Platts in its efforts to confirm such data 

characteristics as completeness (by enabling publishers to 

detect a provider’s omission of certain deals) and accuracy, 

and it will serve as a check against double counting. In fact, 

counterparty information is one of the best means for 

publishers to identify inaccurate or, indeed, fictional 

transactions. The industry should make the provision of 

counterparty names a top priority and resolve confidentiality 

or other issues that some companies say prevent them from 

providing that information. 

Moreover, additional information such as counterparty 

names, buy/sell indicators and time stamps may well be 

useful to determine a market price and to produce better 

benchmarks in relatively illiquid markets or during unusual 

trading conditions when markets are under stress.39 

 

38Market Reporting in North American Natural Gas and Electricity—

Recommendations for Restoring Trust and Transparency: A Call To Action. 

39Id. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-46

Platts acknowledged that, due to the decline in energy trading and the 

fact that some companies have ceased reporting trade data to the Trade 

Press, at some trading points there is very little data from which to 

construct an index: 

Some US gas and electricity pricing points currently are 

showing little or even no trading. Platts editors can use their 

experience to assess the representative prices at which limited 

trading did occur or, in the absence of trades, would have 

occurred. 

Platts is committed to providing as much transparency as 

possible on how such assessments are made and what method 

is used to produce a given price. In US gas markets in recent 

months, Platts has used its traditional index methods for 

trading points that are sufficiently liquid and a broader 

assessment process when we have concluded that 

transactional data alone provides an insufficient base for 

analysis. Once the market shows signs of stabilizing, Platts 

will provide a clear statement on how it intends to assess US 

gas markets in the longer term.40

Platts recognizes the value of showing the degree of liquidity in the 

markets for which it publishes price indices and states that it is 

currently publishing the total trading volume for some of its indices 

and is moving toward publishing volumes for more of its price indices: 

Platts agrees with those who assert that the degree of liquidity 

of a given market should be disclosed by publishers in some 

fashion. It already provides information on liquidity for many 

of its US gas and electric benchmarks, and is moving toward 

expanding the provision of that type of information. While 

volumetric information may be subject to misinterpretation or 

may even encourage attempts to manipulate markets, Platts is 

committed to providing a window on the depth of the trading 

points it covers.41 

NGI 

On September 16, 2002, NGI announced that it was proposing 

modifications to its index price methodology for both its daily and 

weekly indices. The proposed modifications were designed to increase 

 

40Id. 

41Id. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-47

the accuracy of the reported indices and more accurately reflect the 

way market participants are doing business. Specifically, NGI 

recognized the move away from negotiated fixed-price deals during 

bid week toward basis trading for the monthly market. NGI also stated 

that for several years they have been aware that some portion of the 

deals reported to them as fixed price have, in fact, been physical basis 

transactions that it has struggled to identify and remove from its 

calculations. 

NGI proposed including the basis deals in the index and offered two 

suggestions for doing so: (1) the basis trades would include physical 

basis deals done during the last 3 days of the NYMEX trading before 

the near-month contract expires or (2) the basis trades would only 

include quotes from the last day of trading or the settlement day. 

In addition, NGI asked its survey participants to report, wherever 

possible, counterparty information on baseload transactions and the 

date and/or time of the transaction (in addition to price and quantity). 

NGI states that the counterparty and time/date information helps them 

verify that reported transactions meet their survey criteria and helps to 

resolve questions regarding the veracity of certain data when outliers 

in the data are encountered. Moreover, NGI stated that a large portion 

of reporting companies were currently including counterparty and or 

date/time information. 

IntercontinentalExchange 

ICE is now computing indices, especially for next-day products, based 

on a volume-weighted average of the complete set of trades on its 

platform. This provides a way to avoid the sampling bias, 

manipulation, and verification problems associated with conventional 

energy indices constructed by the Trade Press and suggests that it is 

feasible to impose standards on indices to ensure their objectivity. In 

fact, ICE is encouraging the creation of swap contracts based on its 

next-day gas and power indices (“ICE swaps”). ICE has retained Ernst 

and Young, LLP to audit its procedures and verify to the marketplace 

the integrity of its process. 

In October 2002, ICE announced the formation of the 10x Group, 

which publishes electricity and natural gas price indices directly from 

trades on the ICE platform. In addition, ICE has added a trade 

confirmation process, eConfirm, which has the ability to confirm 

trades conducted at over 100 over-the-counter brokerages and trading 

arenas. ICE describes the system as follows: 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-48

The eConfirm system matches a participant’s trade data to its 

counter party’s data to execute confirmations and identify 

discrepancies in real time, contrasting to the manual method 

of confirming trades and reconciling voice broker invoices 

which may typically take days or weeks. eConfirm matched 

trades are considered to be legally binding under identical 

Intercontinental participant agreements that counter parties 

must execute in order to be active on the system.42

ICE states that as of February 19, 2003, there were 28 energy 

companies using eConfirm and those companies had used eConfirm to 

confirm more than 75,000 trades occurring at 49 different brokers and 

execution venues. Along with the trades made over the ICE platform, 

those trades confirmed by the eConfirm system are used in the 

calculation of the 10x published price indices. In addition, ICE 

announced an agreement with Prebon (a large energy product voice 

broker) in which Prebon will use the eConfirm system for all of its 

energy trades, and those trades will be included in the database used in 

calculating ICE’s price indices. 

In short, ICE (through its 10x subsidiary) is in the process of 

constructing price indices that are based solely on actual, verifiable 

trades from its platform or through its confirmation process. 

Moreover, with the agreement of a major voice broker to use ICE’s 

confirmation system, the volume of trades reflected in its published 

indices is increasing. Staff is encouraged by this development and sees 

it as an important part of the necessary reforms to the price index 

reporting process. 

Staff Reaction to the 

Proposed Changes 

Staff commended the Trade Press’s efforts to increase the accuracy of 

the indices included in the Initial Report. The further revisions to the 

process for reporting trade data are also positive developments. 

Combined with the establishment of internal controls on the part of the 

companies providing data to the Trade Press, the entire process has 

improved significantly. It is Staff’s position, however, that the process 

is fundamentally flawed because the Trade Press data are still not 

subject to independent verification. In order for the published indices 

to be reliable, there must be a way to audit the entire information 

chain. The chain consists of (1) the actual trades, (2) the data provided 

by the companies to the reporting firms, (3) the data used by the 

 

42IntercontinentalExchange press release, February 19, 2003. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-49

reporting firms to calculate the indices, and (4) the method for 

calculating the indices. 

As discussed in the Initial Report, the Trade Press has been willing to 

describe its methodology for calculating the prices despite its 

unwillingness to make the data available to Staff or anyone else for 

auditing. Combined with the industry changes in the data reporting 

process and the Commission’s data filing requirements, three of the 

four components of the information chain (the actual trades, the data 

provided by the companies to the reporting firms, and the method for 

calculating the indices) could be audited. However, as long as the 

companies publishing the indices continue to refuse to disclose the 

actual calculations of the published price indices, the information 

chain cannot be audited and the Commission cannot verify the 

accuracy of the published indices. Therefore, Staff recommends that 

only price indices calculated from actual trades that can be verified by 

the Commission should be used as the basis for any Commissionapproved sales of natural gas or electricity. 

Future Index Reporting 

 

As noted throughout this chapter, there have been significant 

improvements in the price-reporting process on both sides. Companies 

have moved the trade data reporting function to the risk management 

offices. The trading data flow directly from the companies’ dealcapture system to the risk management office, and the accuracy of the 

data submitted to the Trade Press is verified and certified by the chief 

risk officer. The Trade Press is now requiring counterparty information 

for all data they receive to ensure the validity of the data and the 

accuracy of the published price indices. The Trade Press has long held 

the position that this is necessary, and Staff strongly agrees. Electronic 

platforms such as ICE have begun publishing indices based on trades 

coming directly from the platform. 

It is important for index construction to be objective and address the 

fundamental problems that have been identified. The problems of 

sampling bias, manipulation, and verification are not inherently 

difficult and can be overcome with a fresh perspective and at a 

relatively modest cost. 

A variety of trading systems exist, including electronic platforms, 

voice brokers, hybrid markets, and trading floors. However, in all of 

these designs it is feasible to compute the average price over a 

specified period of time. There is no reason for prices to reflect the 

impression of individual traders. Instead, they should reflect the reality 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-50

of the actual trades. The approach taken by ICE to compute its indices 

by providing the volume-weighted average execution price for the 

specified period applies not only to ICE and other electronic platforms, 

but also to individual voice brokers, hybrid markets (a combination of 

a voice broker and an electronic platform), and even trading floors. 

This raises the question of how to enforce these standards. 

Any marketer or broker could be required by “anti-fraud” regulations 

or legislation to provide accurate index information (such as average 

prices and volume). This should be a basic requirement for a market 

center such as a trading platform, broker, or trading floor. Although 

not all market contexts have such reporting requirements (e.g., foreign 

exchange trading does not have these restrictions), they are important 

for domestic energy markets in light of the extent of reliance on index 

prices for pricing physical flows and the small number of market 

participants for many products (which leads to the potential for market 

manipulation). Similarly, our discussion of (ex post) transparency in 

Chapter IX emphasized the value of requiring timely trade reports; this 

could be enforced by requiring that these reports be subject to 

appropriate anti-fraud standards. The data and informational 

requirements for trade reporting are much stronger than those for index 

reporting, which is actually an aggregate form of trade reporting. 

Services that purport to measure index prices across platforms or voice 

brokers should be governed by the same anti-fraud rules. Acceptable 

indices in this context should also provide appropriate 

volume-weighted averages to aggregate across portions of the 

marketplace. The computation of such measures would require 

average prices and volumes from those markets and/or brokers, whose 

prices are included in the benchmark. 

This raises the question about whether reasonable indices could be 

computed solely from a single online platform or two (such as ICE and 

TradeSpark) with an automated computational process. Because such 

an index would only reflect online transactions, it would not reflect all 

of the buying and selling of a particular product. Staff recognizes that 

in a perfectly functioning market, arbitrage would drive the prices 

between on- and off-line exchanges together. However, Staff has 

learned from this investigation that energy markets are not always 

perfectly functioning. As such, the ideal index should capture as much 

of the entire universe of trades as possible. Along that line, as 

discussed earlier in this chapter, at least one online exchange has 

entered into an agreement with a major voice broker that would 

include the broker’s transactions in its price index. 

 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-51

Staff Recommendations to 

the Commission 

Staff makes the following recommendations for the Commission to 

consider regarding the characteristics of any future published price 

indices and Commission action to ensure the accuracy and integrity of 

price indices: 

1. Any company publishing price indices to be used as a basis for 

Commission-jurisdictional transactions, e.g., natural gas pipeline 

balancing or market-based electricity pricing, should be subject to 

audit by the Commission to ensure the accuracy of the data going in 

and the calculations themselves. That is, an index that meets the 

requirements established by the Commission for use in Commissionjurisdictional transactions would have the Commission’s seal of 

approval. All data used in the index calculation, including data that are 

thrown out (e.g., outliers, questionable reported trades, trades reported 

without counterparty verification), should be available to the 

Commission. In the Initial Report, Staff described the verification, 

auditing, and oversight procedures associated with NYMEX energy 

trading. Staff suggests that these procedures should serve as a model 

for price index reporting in the future. The characteristics of NYMEX 

and its price index calculations are as follows: 

♦ NYMEX is an organized exchange subject to CFTC regulation. 

♦ NYMEX is required by the CFTC to maintain and enforce an 

internal auditing mechanism and to maintain records of trading 

activity so a clear audit trail is possible. 

♦ NYMEX is required to conduct, with CFTC oversight, market 

surveillance and trade surveillance designed to prevent market 

manipulation and other anti-competitive activity. 

♦ The Futures Trading Practices Act requires that trade information 

be submitted to NYMEX and time-stamped within 1 minute of a 

trade. NYMEX requires its traders to use a special trading pad that 

provides NYMEX with an unalterable audit trail through the use of 

individually numbered, time-stamped computer scans of trader 

records. 

2. The Commission should condition all market-based rate and blanket 

natural gas sales certificate authority on companies providing 

complete, accurate, and honest information to any entity that publishes 

price indices. The information must be detailed transactional data that 

includes: 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-52

♦ Price. 

♦ Volume. 

♦ Delivery point. 

♦ Duration (i.e., hourly, daily, monthly). 

♦ Date and time (to the minute) of the transaction. 

♦ Whether the transaction is a purchase or a sale. 

♦ Counterparty. 

It must be clear that manipulating index prices is a violation of the 

tariff and grounds for revoking market-based pricing or blanket natural 

gas sales authority and for requiring disgorgement of any profits 

resulting from the manipulation. 

 

3. The Commission should require that jurisdictional entities retain all 

information concerning their transactions and any and all information 

submitted to any entity publishing natural gas or electricity price 

indices and provide it to the Commission upon demand. Such 

information would promote more transparent markets and reduce 

incentives to manipulate or attempt to manipulate energy markets. For 

example, the CFTC requires that “[a]ll books and records required to 

be kept by the Act or by these regulations shall be kept for a period of 

5 years from the date thereof and shall be readily accessible during the 

first 2 years of the 5-year period. All such books and records shall be 

open to inspection by any representative of the [CFTC] or the United 

States Department of Justice.”43

4. The Commission should approve standard product definitions for 

published natural gas and electricity price indices used in jurisdictional 

transactions and standard methodologies for calculating the price 

indices. 

Staff has a specific recommendation for an alternative to the published 

price indices that meets the criteria specified above. That is, the 

Commission should require any jurisdictional transaction that is based 

on a published price index to be taken from an index that is calculated 

directly from the trade data from one or more many-to-many electronic 

exchanges and voice brokers that meet all of the criteria specified 

above. The exchange or voice broker must be audited by an outside 

entity, and the audit must be subject to Commission review. An index 

calculated as such would be free from the ability and incentive of 

 

43Commodity Futures Trading Commission Commodities Exchange Act 

Regulation 1.31. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-53

traders to manipulate the prices and would be feasible in terms of 

implementation cost, time, and verification. 

Staff further recommends that the process for establishing standards 

for price reporting be established by the Commission, with input and 

cooperation from the energy industry and the price reporting firms. In 

addition, other government agencies, such as the CFTC and the Energy 

Information Administration, should be involved in the process. The 

process should begin with a technical conference at FERC.44 

As described throughout this chapter, there are a significant number of 

companies whose employees manipulated or attempted to manipulate 

the published price indices by reporting inaccurate or misleading data 

to the Trade Press. Those manipulations and attempts to manipulate 

the published price indices may involve criminal violations. In fact, as 

of February 28, 2003, United States Attorneys have filed criminal 

charges against two former traders (one from Dynegy and one from El 

Paso Merchant Energy). Staff has provided the United States 

Attorneys’ Offices any relevant information regarding these cases and 

will continue to do so. In addition, Staff has provided other 

government agencies (including the CFTC and the SEC) with any 

relevant information regarding their investigations of index price 

reporting and will continue to do so. 

Also, as described in this chapter, many of those companies have taken 

internal measures to correct the problem, such as firing or disciplining 

employees who manipulated or attempted to manipulate the indices; 

moving the reporting process away from the trading desk and toward 

the risk management office; and having a company officer attest to the 

accuracy of data reported to a trade publication. 

Staff recognizes the importance of accurate price indices to the overall 

health of competitive energy markets. The companies discussed at 

length in this chapter are significant participants in U.S. electricity and 

natural gas markets. In order for the published price indices to be 

accurate and credible, they must receive complete and accurate 

information from these companies. As such, Staff recommends that the 

following companies be required to show the Commission that they 

have fixed their internal processes for reporting trading data to the 

Trade Press: 

♦ Dynegy 

♦ Aquila 

♦ AEP 

 

44Commission Staff has scheduled a technical conference relating to the issue for 

April 24, 2003. 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-54

♦ El Paso Merchant Energy 

♦ Williams 

♦ Reliant 

♦ Duke 

♦ CMS 

♦ Mirant 

♦ Coral 

♦ Sempra Energy Trading 

At a minimum, these companies need to show the following: 

♦ Those employees, including trading desk heads and managers, who 

participated in manipulations or attempted manipulations of the 

published price indices have been disciplined. 

♦ The company has a clear code of conduct in place for reporting 

price information. 

♦ All trade data reporting is done by an entity within the company 

that does not have a financial interest in the published index 

(preferably the chief risk officer). 

♦ The company is fully cooperating with any government agency 

investigating its past price reporting. 

Conclusion 

The process for reporting natural gas price indices was fundamentally 

flawed and must be fixed. Traders had the ability and incentive to 

manipulate the published indices and they did so. Given the degree of 

systematic manipulation described in this chapter, the published 

indices could not possibly be accurate based solely on the publishers’ 

editorial judgement, the traders’ feel for the market, or the hope that 

competing traders could offset each other’s false reporting. 

Staff began the investigation looking for evidence of energy price 

manipulation in the West. Staff found evidence of manipulation (direct 

and indirect) of the published natural gas price indices at significant 

trading points all over the United States—the U.S.-Canada border in 

Washington (El Paso), Oregon and San Francisco (Dynegy), the Gulf 

Coast (AEP), the Great Lakes (CMS), the Northeast (Williams), the 

Henry Hub in Louisiana (Enron), and the Southern California-Arizona 

Border (Enron and Reliant). 
Chapter III 

Docket No. PA02-2-000 Price Manipulation in Western Markets III-55

In many cases, electricity prices are directly (through explicit 

contracts) or indirectly (through the generation costs of electricity 

suppliers) determined by natural gas prices. Therefore, the 

manipulation of natural gas prices also affected electricity prices. As 

the agency of the U.S. Government with the statutory obligation to 

ensure just and reasonable electricity rates, the Commission cannot 

rely on a recipe of offsetting false reports, traders’ feel for the market, 

and editorial judgement for accurate price indices. 

As noted in this chapter, there has been a movement within the 

industry to fundamentally reform the price reporting process. 

Suggestions for reform and tangible reforms have come from market 

participants, risk officers, the trade publications themselves, new 

entrants into the price reporting business, government agencies, 

consumer groups, and others. Moreover, Commission Staff will 

convene a technical conference on April 24, 2003 on the issue of price 

reporting, bringing together these parties and working toward a 

solution. It is clear that the parties involved recognize the problem, 

agree that a competitive energy market must have accurate price 

indices to function properly, and are willing to make changes to the 

process in order to ensure that the indices are accurate and reliable. 
Chapter IV 

Docket No. PA02-2-000 IV-1 Price Manipulation in Western Markets 

IV. Staff Alternative Mitigation Proposal 

Summary and Conclusions 

In this and previous chapters of this Report, Staff concludes that 

California spot gas prices were artificially high due to market 

dysfunctions, illiquidity, misreporting, and a rupture causing an 

abnormal pipeline capacity shortage. The spot gas prices reflected 

extraordinary basis differentials that far exceeded the cost of 

transportation and reached levels that would never have been sustained 

in a competitive market. The effects of these inflated gas prices were 

greatly magnified because they were used in the California Refund 

Proceeding to compute clearing prices for the entire electric spot 

power market. While there is no way to precisely replicate the level 

that spot gas prices would have reached in a competitive market, Staff 

recommends the use of producing-area prices plus transportation as a 

proxy for competitively derived gas prices in computing the marketclearing prices in the California Refund Proceeding. Over the 9-month 

refund period, Staff’s proposal would reduce gas costs used in the 

refund formula by $7.03 in southern California and $4.18 in northern 

California, or about $5.60 on average. 

That said, many generators paid these distorted gas prices and 

fundamental fairness dictates that they be able to recover their costs. 

Accordingly, Staff also recommends that generators be made whole 

for the gas prices they paid, but that this recovery be on a dollar-fordollar basis and not be part of the market-clearing price. 

Introduction 

In its July 25, 2001 Order, the Commission established the scope and 

methodology for calculating refunds for bulk power sales in the 

California spot power markets made between October 2, 2000 and 

June 20, 2001. The prescribed methodology would determine the 

mitigated market-clearing price (MMCP) based on the heat rate of the 

least efficient generator dispatched in the ISO’s real-time energy 

market multiplied by the spot price of gas. The purpose of this 

methodology was to “provide prices that emulate closely those that 

would result in a competitive market and that provide generators with 

a reasonable opportunity to recover their costs.”1

In its August 13, 2002 Initial Report on this investigation, Staff 

concluded that the California spot price gas indices may have been 

 

1

95 FERC & 61,418, mimeo, p. 38. 
Chapter IV 

Docket No. PA02-2-000 IV-2 Price Manipulation in Western Markets 

manipulated and were not appropriate for price mitigation. Staff 

recommended that mitigated market-clearing prices be based on 

producing-area spot index prices plus a transportation allowance. To 

the extent that generators paid higher prices for gas to nonaffiliated 

suppliers, these costs would be recoverable though a fuel uplift offset 

to refund obligations. Comments filed in response to the Initial Report 

assert that despite Staff’s concerns regarding index manipulation, 

generators did in fact pay the California spot price for gas, and the spot 

gas price was driven by fundamental supply and demand forces. 

In concluding this investigation, Staff has determined that the 

California spot gas prices were affected by the same factors that 

rendered the electric power market dysfunctional, were closely linked 

to the price levels prevailing for electric power, and reached 

extraordinary levels in part due to pipeline capacity shortages, 

speculative trading, and attempted market manipulation, including 

index price misreporting. Staff concludes that the Commission’s 

objective of creating mitigated prices that would emulate the result of 

a competitive market cannot be achieved by using California gas spot 

prices. 

Staff reaffirms its recommendation that the Commission modify the 

market-clearing price formula in the California Refund Proceeding to 

use producing-area prices plus a tariff rate transportation allowance 

instead of California spot gas prices. Staff believes that the California 

spot gas prices would have closely tracked producing-area prices plus 

transportation had the gas market been free from the distorting 

influence of electric market dysfunction and attempted price 

manipulation and only influenced by the interaction of high demand 

and limited supply. Some portion of the premium over producing-area 

prices also reflected, to some degree, pipeline capacity shortages 

including the El Paso Carlsbad rupture. Ideally, the portion of the 

increased border prices attributable to legitimate scarcity should be 

reflected in the market-clearing price. However, Staff does not believe 

the effects of scarcity can be separated from those of market 

dysfunction and price manipulation. Therefore, Staff recommends that 

fuel input costs above the producing-area cost allowance should be 

recoverable as a refund offset depending on each generator’s heat rate, 

but would not become an input to the market-clearing price. 

In the Initial Report, Staff acknowledged that its proposed method for 

calculating the MMCP and refunds for California was a regulatory 

response to a breakdown of the California electricity market: 

Staff’s proposed substitute is a regulatory solution to a market 

failure. Staff recognizes that the basis differential between 
Chapter IV 

Docket No. PA02-2-000 IV-3 Price Manipulation in Western Markets 

trading points (in this case, between the western production 

basins and the California delivery points) represents 

differences in fundamental supply and demand conditions 

between points, particularly the scarcity of natural gas due to 

limited gas transportation to California, and is an important 

signal for both buyers and sellers. Under normal 

circumstances, that basis differential should be preserved so 

the MMCP is the true marginal cost of the last plant 

producing electricity in California. However, during the 

period in question, circumstances were not normal. 

California’s electricity market was in crisis, and the 

combination of the inelastic demand for electricity and the 

fact that natural gas was the fuel used by the marginal 

electricity generators was transmitting the problems in the 

electricity market back to the gas market. That is, electricity 

generators in California would be willing to pay almost any 

price for natural gas because they would be able to pass any 

gas costs through the wholesale electricity market. Given 

these conditions and the problems with the published 

California natural gas price indices described above, Staff 

finds that the proposed substitute, along with the opportunity 

to recover verifiable gas costs that reflect the scarcity 

premium, as specified above, is the best way for the 

Commission to establish just and reasonable rates for the 

refund period. 

The facts uncovered in the investigation since the August 2002 Initial 

Report confirm Staff’s position that the California electricity market 

was fundamentally flawed and that the dysfunction in the electricity 

market fed back into the natural gas market. In fact, due to the 

influence of EnronOnline (EOL) and the other problems described in 

this Report, the natural gas market at the California border was itself 

one of the forces driving the meltdown of the California electricity 

market. 

The proposed solution in this chapter refines Staff’s August 2002 

proposal by allowing generators to recover costs and earn a fair return 

on their investment while protecting California consumers from unjust 

and unreasonable electricity prices. It allows the companies that made 

investments in efficient generators to keep the profits derived from 

generating electricity at a lower cost than less efficient generators (by 

setting the MMCP as the marginal heat rate times the basin-plustransportation natural gas price) without giving them an “efficiency 

bonus” by leveraging the portion of the natural gas price that is largely 

attributed to the market dysfunctions described throughout the Report, 
Chapter IV 

Docket No. PA02-2-000 IV-4 Price Manipulation in Western Markets 

which would come at the expense of the California utilities and 

ultimately of California consumers. 

The proposed methodology does, however, recognize the need for 

generators to recover the cost of producing electricity in California 

during the refund period. Many generators actually paid index prices 

and will receive a one-for-one payment to recoup their costs. As 

described in this chapter, the California index price reflects the 

scarcity of the natural gas delivered to the California border along with 

the dysfunctions and manipulations of the market. Ideally, Staff would 

separate the scarcity from the manipulation and dysfunction and 

calculate a price that reflected only the true scarcity. In Staff’s view 

that process, if possible, would take years. Staff cannot recommend 

that this uncertainty and imprecision be introduced into a clearing 

price and used to value all the power in an entire market. Staff’s 

proposal strikes a balance by using the basin-plus-transportation price, 

which reflects no scarcity for the clearing price, and using the 

California index price, which reflects scarcity as well as market 

dysfunction and manipulation for the cost recovery. It protects 

California consumers from the multiplier effect of running the 

California index price through the MMCP without unduly penalizing 

generators who paid inflated prices for gas in the spot market. 

Throughout this Report, Staff has proposed penalties to those who did 

manipulate the natural gas market and remedies so that it does not 

happen again. Generators who purchased gas at artificially high prices 

due to market dysfunction and manipulation do not deserve to be 

penalized any more than the California electricity consumers who 

clearly paid excessive electricity prices due to the gas and electricity 

market manipulation and dysfunction. 

Why California Gas Spot 

Prices Should Not Be Used 

for Price Mitigation 

In specifying that California spot gas prices be used to emulate the 

outcome of a competitive market, the Commission assumed that the 

gas spot market was truly competitive and could provide a reliable 

foundation for emulating the outcome of a competitive power market. 

Staff believes, based on information developed in this investigation, 

that the prices established in the gas spot market were not the outcome 

of fundamental supply and demand forces, but were affected by 

dysfunctional spot electricity markets, an illiquid spot gas market, 

speculative trading, and, in some instances, market manipulation. All 
Chapter IV 

Docket No. PA02-2-000 IV-5 Price Manipulation in Western Markets 

of these factors influenced the California spot prices. While the 

analysis in Chapter II of this Report attempts to quantify the impact of 

speculative trading and churning on EOL, simply removing that 

portion from the California spot price would not remove all vestiges of 

market dysfunction from the gas prices used for power market price 

mitigation. 

Gas Prices Were Driven by 

Power Prices Once Pipeline 

Capacity Became 

Constrained 

As Figure IV-1 indicates, the relationship between gas and electric 

power prices changed over time. In the summer and fall of 2000, 

electric power prices rose to very high levels while gas prices stayed 

relatively low. Once colder weather arrived in November and 

December 2000, and the combined heating and power load fully used 

available pipeline capacity, gas prices started to generally follow 

electric prices. 

Figure IV-1 

Palo Verde Power Price vs. California Gas Price

High Power Prices Preceded Gas Price Rise

$0

$100

$200

$300

$400

$500

$600

$700

$800

1/3/002/3/003/3/004/3/005/3/006/3/007/3/008/3/009/3/00

10/3/0011/3/0012/3/00

1/3/012/3/013/3/014/3/015/3/016/3/017/3/018/3/019/3/01

10/3/0111/3/0112/3/01

1/3/022/3/023/3/024/3/02

$/Mwh

Palo Verde Cost of generation fuel at 12,000 Btu/Kwh

Gas prices followed electric prices

after pipeline capacity constrained
Chapter IV 

Docket No. PA02-2-000 IV-6 Price Manipulation in Western Markets 

This trend illustrates a fundamental dynamic in natural gas pricing: in 

a nonconstrained market, gas prices are driven by seller competition 

and the seller’s marginal cost; in a constrained market, prices are 

driven by buyer competition for scarce resources, and prices reach the 

buyer’s value for gas—in this case, the value of gas for power 

generation. In other words, in the capacity-constrained California 

market, gas prices were driven in substantial part by power prices. In 

this regard, Staff agrees with the observation of Henning and Sloan of 

EEA in comments filed by Duke Energy:2

Indeed, in California, when power prices exploded to record 

heights, power generation customers were willing to pay 

astronomically high gas prices since electricity prices made it 

economically feasible to do so. 

Pipeline Capacity 

Constraints Were Not 

Entirely Market Related 

During the refund period, the El Paso pipeline was operating at 

reduced capacity due to the Carlsbad pipeline explosion. This reduced 

El Paso’s capacity to California by 270 MMcf/d, more than 10 percent 

of its average actual deliveries. The loss of this capacity was clearly 

not anticipated, but it had a large impact on price. Had that capacity 

been available, the spot market price would in all likelihood have been 

substantially lower than the price that was paid. When warmer weather 

returned during the first 10 days of January 2001, market demand 

dropped by 240 MMcf/d compared with the last 10 days of December 

2000. The corresponding price differential between California and 

Southwest price points dropped from $7.25 to $2.20/MMBtu.3

 While 

this remains some four times higher than transportation costs to the 

border, the difference strongly implies that the Carlsbad rupture 

contributed significantly to the extraordinarily high California spot gas 

prices. Although a pipeline outage has an element of legitimate 

scarcity, there is no way to isolate these scarcity costs. In addition, 

Staff does not believe that there is any compelling reason to include 

 

2

Comments of Duke Energy filed October 15, 2002 in Docket No. EL00-95-045, 

Exhibit B, p. 11. 

3

For the period from December 21-31, 2000, average El Paso deliveries to California 

were 2,788,244 Mcf/d, the average California spot price was $16.73, and the average 

Southwest spot price was $9.48. For the period from January 1-11, 2002, average El 

Paso deliveries to California were 2,547,007 Mcf/d, California spot prices averaged 

$11.40, and Southwest prices averaged $9.20. 
Chapter IV 

Docket No. PA02-2-000 IV-7 Price Manipulation in Western Markets 

costs related to such an abnormal event in the clearing prices for an 

entire electric spot market. 

California Gas Prices Were 

Artificially High 

As discussed elsewhere in this Report, the investigation has identified 

evidence of gas market dysfunction, speculative trading, and index 

misreporting. These factors, in addition to the linkage between gas and 

electric markets, resulted in artificially high gas prices. Staff 

recommends that the Commission reconsider whether high gas prices 

should automatically mean that generators are entitled to higher 

operating profit, especially if gas prices are found to be artificial. 

Spot Gas Prices Contained a 

Transportation Premium Far 

in Excess of Pipeline 

Transportation Rates 

During the refund period, California spot gas prices reached heights 

never before seen in the California market, rising to $59.42/MMBtu on 

December 11, 2000. On average, southern California spot prices were 

$13.42/MMBtu compared with $5.53 for the Southwest spot supply 

for the refund period.4 The markup over Southwest spot prices 

averaged $7.89 compared with a maximum transportation rate of 

$0.86, including fuel. The markup in excess of transportation costs, 

averaging $7.03, represented 52.4 percent of the reported spot price.5

Figure IV-2 shows the disparity between Southwest spot gas costs and 

southern California spot prices. 

 

4

Southern California spot prices were based on Gas Daily price for SoCal large 

packages. Southwest price was based on the average between Gas Daily Waha and 

El Paso – Bondad pricing points. All Gas Daily prices were the midpoint of the 

common range. 

5

Transport cost: El Paso IT—$0.3968, 3.74 percent fuel at $5.53 average price; 

SoCal GT F5—$0.2542 including fuel. 
Chapter IV 

Docket No. PA02-2-000 IV-8 Price Manipulation in Western Markets 

Figure IV-2 

Disparity Between Southern California and Southwest Spot Prices

 Far Exceeds Transportation Rates

$0

$10

$20

$30

$40

$50

$60

$70

1/3/002/3/003/3/004/3/005/3/006/3/007/3/008/3/009/3/00

10/3/0011/3/0012/3/00

1/3/012/3/013/3/014/3/015/3/016/3/017/3/018/3/019/3/01

10/3/0111/3/0112/3/01

1/3/022/3/023/3/024/3/02

$/MMBtu

Markup over producing area cost plus transportation

Southwest spot + transport

S. California spot average - $13.42

SW spot + trans average - $6.39

During the refund period, the Southwest gas price also reached record 

heights, reflecting commodity value in the producing area. The 

average Southwest price of $5.53 during the refund period was 40 

percent higher than prices in the preceding summer, and more than 

twice the price during the preceding and succeeding winter periods. 

Similar prices existed in northern California. Figure IV-3 shows the 

disparity between the PG&E citygate price and upstream Canadian 

supplies during the refund period. The peak PG&E citygate price 

reached $50.79/MMBtu on December 8, 2000, averaging 

$10.10/MMBtu, compared with $4.79/MMBtu for the AECO 

Canadian producing-area point over the refund period.6

 

 

6

Northern California spot prices were based on the Gas Daily PG&E citygate pricing 

point; AECO prices from Gas Daily. All Gas Daily prices were the midpoint of the 

common range. 
Chapter IV 

Docket No. PA02-2-000 IV-9 Price Manipulation in Western Markets 

Figure IV-3 

Disparity Between Northern California and Canadian Spot Prices

 Far Exceeds Transportation Rates

$0

$10

$20

$30

$40

$50

$60

$70

1/3/002/3/003/3/004/3/005/3/006/3/007/3/008/3/009/3/00

10/3/0011/3/0012/3/00

1/3/012/3/013/3/014/3/015/3/016/3/017/3/018/3/019/3/01

10/3/0111/3/0112/3/01

1/3/022/3/023/3/024/3/02

$/MMBtu

Markup over producing area cost plus transportation

AECO spot + transport

N. California spot average - $10.10

AECO spot + trans average - $5.92

The markup over Canadian spot prices averaged $5.31 compared with 

a maximum transportation rate of $1.13, including fuel. The markup in 

excess of transportation costs, averaging $4.18, represented 41.4 

percent of the reported spot price.7

Under the Market-Clearing 

Price Mechanism, Generator 

Operating Profit Increases 

With the Gas Price 

Artificially High Gas Prices 

Equal Artificially High Profits 

Under the July 25 Order’s mitigation methodology, the gas component 

of the market-clearing price is determined by multiplying the spot gas 

price by the heat rate of the least efficient generator dispatched by the 

ISO. All other generators receive this same price. Generators with heat 

rates more efficient than the market-clearing unit retain the difference 

between the market-clearing price and their actual fuel costs, referred 

to here as gross operating profit. The gross operating profit is a 

function of the gas input price, as shown in Figure IV-4. For example, 

if the least efficient marginal unit has a heat rate of 15,000 Btu/kWh 

 

7

Transport cost: TransCanada—$0.1820 including fuel; PGT IT—$0.2722, 3.06 

percent fuel; PG&E G-AFT—$0.2687; PG&E G-EG—$0.1995, 1.37 percent fuel at 

$4.18 average price. 
Chapter IV 

Docket No. PA02-2-000 IV-10 Price Manipulation in Western Markets 

and the spot gas cost is $5/MMBtu, the gas cost component of the 

mitigated market-clearing price would be $75/MWh. A 10,000 

Btu/kWh unit would incur only $50/MWh in gas costs due to higher 

efficiency, yielding a $25/MWh gross operating profit. At a 

$20/MMBtu gas price, however, the gross operating profit of the 

10,000 Btu unit rises to $100/MWh. At $60/MMBtu, the gross profit 

rises to $300/MWh. 

Figure IV-4 

Generator profitability rises with gas cost

0

100

200

300

400

500

600

700

800

900

1000

5 10 15 20 25 30 35 40 45 50 55 60

Gas Cost $/MMBtu

$/Mwh

Gross operating profit when market price set by 15,000 Btu unit

Gas cost for 10,000 Btu heat rate

Thus, under the July 25 Order, the profitability for generators more 

efficient than the market-clearing unit is directly related to gas input 

prices. The higher the gas price, the higher the average generator’s 

allowed gross operating profit. The single clearing price auction, 

where all sellers receive the price at which the last unit of supply 

clears the market, was an integral part of the California restructuring 

framework. The choice of a single clearing price, as opposed to a 

market design where each seller receives the particular price it 

demands, was the result of an extensive stakeholder process with the 

support of many economists. 

Generator Profitability Rises With Gas 

Cost
Chapter IV 

Docket No. PA02-2-000 IV-11 Price Manipulation in Western Markets 

Modification of the Mitigated 

Market-Clearing Price 

Methodology Is Needed 

As shown above, the July 25 methodology rewards generators who 

paid high gas prices with mitigated power prices that, for most 

generators, produce higher gross operating profit than under normal 

market conditions. Staff believes that California spot gas prices 

reached levels that would not have existed in a competitive gas market. 

The shortage conditions that existed were not wholly market related, 

but rather were in part the result of an abnormality—the El Paso 

Carlsbad rupture. Further, various attempts to manipulate prices, as 

described within this Report, cast doubt on whether the California spot 

prices were legitimate. 

Staff believes that the problems identified with California spot gas 

prices warrant a revision in the Commission’s price mitigation 

methodology. The challenge is to design price mitigation that 

compensates the marginal generator for gas costs incurred in good 

faith to provide needed power supply, while recognizing that unusually 

high gas costs overcompensate other, more efficient generators. While 

efficiency should be rewarded, Staff believes this reward should have 

limits, particularly at the extraordinary and questionable gas price 

levels that prevailed during the refund period. 

Options for Establishing 

Natural Gas Prices for Power 

Price Mitigation 

In Staff’s view there are various approaches the Commission should 

consider to determine the appropriate natural gas price level for 

establishing mitigated power prices. As discussed above, Staff does 

not support using the California spot index price. 

The central problem is to determine what level California spot marketclearing power prices would have reached in a hypothetically 

competitive market, free of the distorting influences of power market 

dysfunction, gas market manipulation, and lack of liquidity. Staff 

submits that there is no clean way of separating the components of the 

artificially high California spot gas prices to determine such a 

hypothetical price level. In Staff’s view, the best way to ensure that the 

mitigated market-clearing price is completely independent of 
Chapter IV 

Docket No. PA02-2-000 IV-12 Price Manipulation in Western Markets 

distortion and manipulation is to substitute producing-area prices plus 

a tariff transportation allowance for California spot prices. This 

approach would approximate gas market conditions had there been no 

electric market dysfunction, no pipeline constraints, and no gas price 

manipulation. As explained in the Initial Report, Staff believes the 

index price for Southwest and Canadian producing areas is reliable and 

was not subject to manipulation because these prices correlate well 

with the larger and more liquid Henry Hub market. 8

Unfortunately, many generators did in fact pay prices that included the 

effect of these factors. Fairness dictates that generators be permitted to 

recover these costs. However, since these costs reflect (at least in part) 

some degree of artificiality, they need not be reflected in the mitigated 

market-clearing price for power. Treating these costs on a dollar-fordollar basis allows the recovery of legitimate scarcity costs and is 

consistent with the approach the Commission adopted in the July 25 

Order for nitrogen oxide credits. 

The remaining issue is the level of costs above the producing-area 

allowance that should be recoverable. Staff proposes that the 

Commission consider three options for determining the level of the 

additional fuel cost pass-through allowance. 

The first option would be to adopt the approach recommended in the 

Staff’s August 13 Initial Report. At that time Staff proposed to limit 

the level of additional fuel cost recovery to the average price of each 

generator’s portfolio of gas supplies from nonaffiliated suppliers. In 

response to that proposal, several commenters pointed out that the 

portfolio approach would penalize generators who managed to keep 

their gas costs below the California spot index price. Determining 

actual costs could involve substantial effort and subjective cost 

allocations. Further, comments indicated that in most cases generators 

did in fact pay the California spot gas index price. 9

The second option would be to determine the additional fuel cost 

allowance based on the California spot gas index rather than on the gas 

portfolio cost. Under this method the cost of fuel over and above the 

production area allowance would be determined by each generator’s 

heat rate multiplied by the amount the California spot index exceeded 

the producing-area index plus fuel and transportation. This approach 

would simplify the additional fuel cost determination and avoid an 

indepth analysis of gas portfolios and costs. Since many generators 

paid the index price for their spot gas, a detailed analysis of their 

 

8

Initial Report at p. 71. 

9

See study by Drs. Wang and Reishus filed by the comment of the Generator Group 

(Mirant, Dynegy, Williams, Duke Energy, and Reliant Energy). 
Chapter IV 

Docket No. PA02-2-000 IV-13 Price Manipulation in Western Markets 

actual portfolios should not produce substantially different results. 

Further, the gas portfolio approach could deprive generators of the 

benefits of responsible fuel cost management. Those generators who 

took the risk of acquiring firm service and supported pipeline capacity 

expansions, for example, would be entitled to keep the difference 

between their fuel costs and the California border price. The marketclearing price for electricity, however, would be based on the 

production area price allowance. 

A third option would base the additional fuel cost allowance on the 

price of actual California daily spot market gas purchases rather than 

rely on the reported indices. This option would still rely on daily spot 

market prices to determine the additional fuel cost allowance, but 

would establish those prices based on a review of actual spot market 

purchases by generators serving the California market. This approach 

would test the claim by the generators that the reported California spot 

market index corresponded closely with actual spot market gas costs. 

This approach would require generators to file actual spot market 

purchase costs, which would be more data intensive than relying on 

the reported gas indices, but would reduce uncertainties as to whether 

the reported index was in fact what generators paid for spot market 

gas. 

How the Alternate MarketClearing Price Mechanism 

Would Work 

The Staff’s proposal for mitigated power price has two components—

an alternate market-clearing price and an additional fuel cost 

allowance. The alternate market-clearing price would be based on the 

fuel cost of the least efficient unit dispatched priced at the producingarea price index plus transportation and fuel. The additional fuel cost 

allowance would be passed through on a dollar-for-dollar basis as an 

offset against refund exposure. 

Figure IV-5 illustrates the separate determination of the marketclearing price and the additional fuel cost allowance at various 

generator heat rates. The figure assumes for illustration that the 

market-clearing unit had a heat rate of 15,000 Btu/kWh and the 

average heat rate for California generators is 10,000 Btu/kWh.10

During the refund period, the average southern California gas spot 

index price was $13.42/MMBtu, and the average Southwest spot price 

 

10The average heat rate at full capacity for generators reported by the California ISO 

in Docket No. EL00-95 was 10,189 Btu/kWh (derived from Exhibit ISO-8). 
Chapter IV 

Docket No. PA02-2-000 IV-14 Price Manipulation in Western Markets 

plus transportation was $6.39/MMBtu. Operation and maintenance 

costs were excluded for the sake of simplicity. 

As illustrated in the figure, the alternate market-clearing price for a 

marginal unit (15,000 Btu heat rate) would be $95.84/MWh and the 

additional fuel cost allowance would be $105.48/MWh,11 for a total of 

$201.32/MWh. While this is the same total price as that produced 

using the California spot price, the market-clearing price would be 

reduced to $95.84/MWh. For a 10,000 Btu heat rate unit, however, the 

additional fuel cost allowance would be $70.32/MWh12 (because the 

more efficient unit uses less fuel), for a total of $166.16/MWh, or 

$35.16/MWh less than the July 25 Order methodology. Again, the 

$70.32/MWh would not be part of the market-clearing price. 

Figure IV-5 

Using Producing Area Prices for the Market Clearing Price

Provides Reasonable Operating Profit

$0

$50

$100

$150

$200

$250

150001400013000120001100010000

900080007000

Heat Rate

$/Mwh

Producing Area Gas Cost avg $6.39 Operating Profit Additional Fuel Cost Recovery Refund

Revised market

clearing price at

SW index

Operating Profit

Gas cost at

SW index 

Passthough of gas 

costs over SW index

Additional reund 

Market clearing price

using S. Ca. spot price

Under the alternate market-clearing methodology, units more efficient 

than the marginal unit would receive an efficiency profit, but that 

profit would be based on the producing-area index price. The 

additional fuel allowance would be based on each individual 

generator’s heat rate and would be passed through as a refund offset, 

but would not be included in the market-clearing price. 

 

11Alternate market-clearing price: $95.84/MWh = 15,000 Btu/kWh × $6.39/MMBtu. 

Additional fuel cost allowance for a 15,000 Btu heat rate: $105.48/MWh = 15,000 

Btu/kWh × ($13.42 - $6.39)/MMBtu. 

12Additional fuel cost allowance for a 10,000 Btu heat rate: $70.32/MWh = 10,000 

Btu/kWh × ($13.42 - $6.39)/MMBtu. 
Chapter IV 

Docket No. PA02-2-000 IV-15 Price Manipulation in Western Markets 

Impact of the Proposed 

Alternate Mitigation 

Methodology 

Figure IV-6 compares, for various periods, the estimated generator 

gross operating profit under the July 25 Order and Staff’s proposed 

alternate mitigation methodology. During the refund period, an 

average generator with a 10,000 Btu heat rate would have earned an 

average gross operating profit of $67/MWh based on California spot 

prices, and $32/MWh under the alternate methodology. 

Figure IV-6 

Operating Profit Comparison

Southern California vs. Southwest Index 

(market clearing price set by 15,000 Btu heat rate, average heat rate at 10,000 Btu) 

$0

$10

$20

$30

$40

$50

$60

$70

$80

1/3/00 - 10/1/00 10/2/00 - 6/20/01 6/21/01-4/24/02

Operating Period

$/MWh

Operating Profit at SW Index Operating Profit at Ca spot index

Comparing the calculated $32/MWh operating profit for the refund 

period with levels in periods before and after shows that the alternate 

methodology satisfies the Commission’s goal of providing generators 

with a reasonable opportunity to recover their fixed costs. During the 

refund period, the average computed operating profit was $32/MWh, 

or 55 percent higher than that of the preceding 10-month period and 

twice the operating profit level experienced in the succeeding 10-

month period. 

The $32/MWh operating profit substantially exceeded the capital 

recovery requirement of a hypothetical new power project. The 

California Energy Commission (CEC) estimates that a new combined 

cycle gas turbine would require capital recovery of between $85 and 
Chapter IV 

Docket No. PA02-2-000 IV-16 Price Manipulation in Western Markets 

$100/kW per year, or $16.17 to $19.03/MWh at a 60-percent plant 

factor.13 As such, gross operating profits were in line with capital costs 

before and after the refund period. This indicates that the single 

clearing price auction produced reasonable results except when the gas 

input prices were artificially inflated. 

Use of Incremental Versus 

Average Heat Rates 

On December 12, 2002, Administrative Law Judge (ALJ) Birchman 

issued his Certification of Proposed Findings on California Refund 

Liability. The ALJ found that marginal heat rates for refund 

determination purposes should be based on the change in heat rate 

over a given load interval rather than the average heat rate for 

generating power at a given load level. The incremental heat rates used 

by the ALJ averaged 12,268 Btu/kWh on a load-averaged basis for the 

refund period, versus the 15,000 Btu/kWh used for illustrative 

purposes in the preceding examples.14 Figure IV-7 shows how 

generator operating profit would be affected by the Staff refund 

methodology if the Commission adopted the ALJ’s heat rate finding. 

 Figure IV-7 

Monthly Operating Profit Using Incremental Heat Rates 

(market clearing price set by incremental heat rate, profit based on average heat rate)

$0

$10

$20

$30

$40

$50

$60

$70

$80

$90

Oct-00 Nov-00 Dec-00 Jan-01 Feb-01 Mar-01 April-01 May-01 June-01

$/MWh

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

Heat Rate Btu/kWh

Operating Profit at Prod index Operating Profit at Ca. spot index ISO incremental heat rates Average heat rate of other units

average heat rate

of marginal unit 

average heat rate

 of units dispatched

 

13California Energy Commission, 2002–2012 Electricity Outlook Report, pp. 32-33. 14Heat rates from Exhibit ISO-3, in Docket No. EL00-95-045. Load averaging based 

on daily system load as reported on the California ISO Oasis Web site. 
Chapter IV 

Docket No. PA02-2-000 IV-17 Price Manipulation in Western Markets 

The figure shows that the combination of the incremental heat rates 

used by the ALJ and the Staff’s recommended producing-area index 

for price mitigation would reduce operating profit levels considerably. 

Using the ALJ heat rates and the California spot gas price, the average 

operating profit would be $41.80/MWh for the average generator 

operating at a 9,400 Btu heat rate. Using Staff’s recommended 

producing-area gas price methodology and the ALJ’s heat rates would 

reduce average operating profit to $20.04/MWh. This level of 

operating profit is within the range needed to support new generation 

investment. 

 

Response to Comments on 

Initial Report 

Did the index reflect what generators actually paid for gas? 

Drs. Wang and Reishus looked at natural gas transaction data for 

Mirant, Dynegy, Williams, Duke Energy, and Reliant Energy 

(Generator Group) for the refund period. They found that the price the 

Generator Group actually paid for gas was nearly perfectly correlated 

with the index price. They conclude that the index price was an 

accurate measure of the market price, contrary to Staff’s conclusions. 

Dr. Van Vactor testified on behalf of Coral Energy. He analyzed the 

reported price data from all of the major natural gas price reporting 

publications and compared the reported natural gas prices with the 

prices posted on another trading platform, IntercontinentalExchange 

(ICE), for the period beginning April 2001. He found that the prices 

were nearly identical during the refund period and concluded that the 

price data from McGraw Hill (Platts), Intelligence Press, and the 

Energy Intelligence Group were accurate. He also cited the similarity 

of the reported prices to those reported on ICE after April 2001 and 

argued that this similarity provides further evidence that the reported 

prices were accurate. 

Staff response: 

Staff believes that the price generators paid correlates closely with the 

index because the purchase agreements were for index-priced gas. 

Since index-based pricing is prevalent in spot market sales and in 

intracompany price determination, it is not surprising that generators, 

at least on paper, paid the index price for gas. The commenters 

misconstrue the premise for Staff’s alternate index proposal. The issue 

is not whether generators paid the index price, but rather (1) whether 

the index price was the result of manipulation, and (2) whether basing 
Chapter IV 

Docket No. PA02-2-000 IV-18 Price Manipulation in Western Markets 

mitigated market-clearing prices on the index emulates the result of a 

competitive market while providing generators with a reasonable 

opportunity to recover their costs. Staff finds that the index price was 

the outcome of market dysfunction and manipulation enabled by 

pipeline capacity shortages and, given the mechanics of the marketclearing price mechanism at high gas prices, over-recovers generator 

costs. 

Staff ignored the fundamental reasons for high natural gas prices at 

the California border during the refund period. 

Many commenters (NGSA, EPSA, Williams, TransAlta, Powerex, 

Anaheim, Burbank, SoCal, LADWP) argue that there are many welldocumented reasons for the high natural gas prices in southern 

California during the refund period. Those reasons include the scarcity 

due to inadequate natural gas infrastructure (as noted by the CEC in its 

study of natural gas infrastructure issues); increased demand for gas 

due to low hydro reserves leading to more gas-fired generation; 

imbalance penalties on the SoCal system; and flaws in the wholesale 

and retail electricity market design, which spilled over into the gas 

market. They argue that Staff ignored those reasons and made a leap to 

gas market manipulation and manipulation of the reported indices. 

Staff response: 

Staff accepts that market manipulation was not the sole cause of high 

California spot gas prices. A portion of the increase in California 

border prices reflected legitimate scarcity. Nevertheless, Staff believes 

that unusually high demand and a shortage of pipeline capacity created 

the opportunity for manipulation, which did occur and did influence 

prices. The various forces and behaviors described in this Report cast a 

cloud over the gas market and taint the reported indices. The 

Commission need not find that all of the price differential between 

producing-area and California pricing points was due to manipulation 

to accept Staff’s recommended alternate mitigation proposal. There is 

no fundamental policy reason that generators are entitled to higher 

gross operating profits simply because gas prices skyrocketed. By 

treating the transportation premium embedded in the gas price as a 

pass-through cost, generators are assured of a reasonable opportunity 

to recover their costs while at the same time assuring that a potential 

taint on gas prices is eliminated from the market-clearing price and 

generator profitability. 
Chapter IV 

Docket No. PA02-2-000 IV-19 Price Manipulation in Western Markets 

How should the MMCP account for scarcity? 

In its Initial Report, Staff argued that the opportunity to recover gas 

costs over and above the production area price will allow parties to 

recover any costs reasonably associated with scarcity. In its August 13 

request for comments on the Staff’s Initial Report, the Commission 

asked the question: “What is an appropriate way to account for 

scarcity?” 

Many commenters stress the point that Staff did not account for 

scarcity in its proposed methodology. SoCalGas and San Diego Gas & 

Electric Company argue that the only way to account for scarcity is to 

use the market prices relied on by market participants trading at arm’s 

length. They state that no formula intended to recreate gas prices 

retrospectively can appropriately account for scarcity. As noted above, 

Dr. Roach suggests that the Commission use the actual prices that gasfired generators paid for spot gas to construct a price, which would 

account for scarcity. 

Staff response: 

Most of the commenters implicitly assume that mitigated power prices 

should be based on spot gas prices regardless of the level of gas prices, 

or whether the gas price levels were artificially high. Staff disputes this 

notion. There is no fundamental principle that requires the 

Commission to allow artificially high gas input costs to produce 

proportionately higher generator gross operating profits. This is 

especially true when a significant portion of the higher gas costs was 

driven by market dysfunction and manipulation in addition to a 

scarcity of pipeline capacity. 

Staff maintains that legitimate scarcity costs cannot be separated from 

the influence of market distortions affecting the California gas market. 

Further, it is not clear whether an effort to emulate the outcome of a 

competitive market should include the influence of abnormalities such 

as the Carlsbad rupture. In Staff’s view, the use of the producing-area 

cost allowance provides generators with a reasonable opportunity to 

recover their costs. As shown above, basing the MMCP on the 

producing-area index plus transportation yields reasonable operating 

profit levels, more than sufficient to support investment in new 

generation. 

Staff recognizes that the proposed methodology, which allows less 

efficient units to charge a higher price, could be construed as 

penalizing more efficient generating units, thus stifling investment in 
Chapter IV 

Docket No. PA02-2-000 IV-20 Price Manipulation in Western Markets 

more efficient generation. The long-term benefit of competitive 

electricity markets comes from the suppliers’ incentive to invest in 

more efficient, cleaner generation in order to maximize its profits. 

More efficient units will earn greater profits by producing at a lower 

cost. However, given Staff’s conclusion that the high natural gas prices 

reflected (in part) market dysfunction and manipulation, part of any 

profit earned by the more efficient units would be due to the higher 

prices resulting from dysfunction and manipulation, the cost of which 

would ultimately be borne by consumers. A price based on market 

dysfunction and manipulation does not send an accurate signal 

regarding the profitability of investment. Staff’s proposed 

methodology strikes a balance between protecting customers from 

prices based on market manipulation and dysfunction and protecting 

suppliers’ ability to earn a fair profit in a competitive market. 

California Parties’ concerns about fuel cost recovery 

The California Parties argue that the Commission should not allow a 

cost-based recovery mechanism for fuel costs above the producing 

area allowance because this would mix market-based rate and costbased recovery mechanisms. The California Parties assert that the 

Commission has already provided a cost-of-service alternative 

mechanism for those parties who find that the July 25 MMCP 

methodology provides insufficient revenue to cover their costs. The 

California Parties argue that the fuel recovery mechanism proposed in 

the August 13 Initial Report is flawed because (1) it would depend on 

unit heat rates, which vary with load, and some portion of that load is 

serving bilateral contracts rather than Cal ISO and Cal PX spot 

markets; (2) bids to the Cal ISO and Cal PX were not unit specific, 

thus making heat rate determinations problematic; and (3) more 

efficient generators may not need a fuel recovery allowance to remain 

profitable. 

Staff response: 

Staff submits that the proposed additional fuel cost recovery 

mechanism is a pragmatic adjustment to the market-based 

methodology prescribed by the July 25 Order. The cost-of-service 

alternative would still be available to generators or marketers who are 

not satisfied with the revised MMCP methodology. Since the proposed 

modification to the July 25 methodology would substantially reduce 

the MMCP below the cost of generating power using California spot 

market gas, the additional fuel cost recovery mechanism is needed for 

the market-based option to be fair and realistic. 
Chapter IV 

Docket No. PA02-2-000 IV-21 Price Manipulation in Western Markets 

With regard to heat rate determination, Staff does not agree that a 

generator should allocate its fuel consumption to different services at 

different loading levels. Staff proposes that a single heat rate for each 

10-minute interval should apply to all services the generator provides. 

With regard to the concern that the Cal ISO and Cal PX bids were not 

unit specific, Staff asserts that the generators must make a showing of 

which units served the Cal ISO and Cal PX market in the Compliance 

filing phase of the refund proceeding. The California Parties will have 

an opportunity to review this submission and advise the Commission 

on their concerns at that time. With regard to the level of profitability 

of specific generators, Staff’s analysis in this Report addresses 

generator operating profitability in detail. The proposed methodology 

reduces generator profitability but provides a reasonable opportunity to 

recover costs consistent with the goal of the price mitigation as 

discussed in the July 25 Order.