STATE OF

THE MARKETS

REPORT

ASSESSMENT OF ENERGY MARKETS FOR THE PERIOD

JANUARY 1, 2002 THROUGH JUNE 30, 2003

STAFF REPORT BY THE

OFFICE OF MARKET OVERSIGHT

AND INVESTIGATIONS

FEDERAL ENERGY REGULATORY

COMMISSION

JANUARY 2004

DOCKET MO4-2-000
P R E F A C E

This is the Federal Energy Regulatory Commission’s 

second State of the Markets Report and the first 

prepared by the Office of Market Oversight and 

Investigations (OMOI). The report covers an 

assessment period from January 2002 through 

June 2003 and covers electricity, natural gas and 

related financial market conditions and trends. In 

contrast to OMOI’s seasonal assessments, which focus 

on the near future, this report examines market 

performance in the recent past. In the State of the 

Markets Report, OMOI presents findings regarding 

market conditions relevant to the Commission and 

identifies emerging policy issues that may soon 

require the Commission’s attention.

The Commission created OMOI in April 2002 to focus 

its efforts on energy market oversight. Any errors in 

this report are the responsibility of OMOI alone and 

not of the Commission as a whole.

I want to commend the able leadership team for 

this project: Mary Beth Tighe and Cynthia Wilson. 

Other members of this team are listed in the 

Acknowledgements.

We encourage readers to provide feedback on this 

OMOI product by filling out the State of the Markets 

Report Evaluation Card below, sending comments 

to an e-mail address specifically set up for this 

report, SOM.2003@FERC.gov, or by contacting staff 

referenced in the acknowledgements at:

OMOI (State of the Markets Report)

FERC

888 First Street, N.E.

Washington, D.C. 20426

202-502-8100

A fair energy marketplace is everyone’s 

responsibility. Please do your part. If you encounter 

inappropriate energy market behavior, contact our 

ENFORCEMENT HOTLINE toll-free by telephone at 

1-888-889-8030 or via e-mail at Hotline@FERC.gov.

Thank you.

WILLIAM F. HEDERMAN

Director

Office of Market Oversight and Investigations

Introduction 1

Summary 3

Approach 4

Key Findings of the Report 6

Electricity Market Performance 17

Market Structure 21

Prices, Market Activity, Congestion and Mitigation 28

Market Design and Price Transparency 53

Risk Management 59

Infrastructure Investment 64

Summary of Electricity Market Performance 76

Natural Gas Market Performance 77

Market Structure 78

Prices and Locational Basis 80

Risk Management 86

Transparency 91

Investment 94

Summary of Natural Gas Market Performance 101

List of Appendices

Appendix 1: Regional Maps 103

Appendix 2: Generating Capacity Additions 109

Appendix 3: Generation Ownership Concentration 

in Regional Electricity Markets 111

Appendix 4: Description of Natural Gas Markets 

and Products 119

Appendix 5: Electric Power Fuel 

Consumption Trends 121

Appendix 6: Gas and Electric Price Points 123

Appendix 7: List of Acronyms and Abbreviations 125

Appendix 8: Glossary 127

Appendix 9: List of Figures and Tables 133

Acknowledgements 137

TABLE OF CONTENTS
S T A T E O F T H E M A R K E T S

1

T

he Federal Energy Regulatory Commission (FERC) regulates the transmission and sale of natural 

gas and electricity for resale in interstate commerce to ensure that customers have dependable, 

affordable energy through competitive markets. One of the Commission’s strategic goals is to 

protect customers and market participants through vigilant and fair oversight of energy markets in 

transition. To pursue this goal, the Commission promotes understanding of energy market operations and 

assesses market conditions using objective benchmarks in order to create pro-competitive market structure 

and operations. 

The purpose of this State of the Markets Report, produced by FERC’s Office of Market Oversight and 

Investigations (OMOI), is to assess the competitive performance and efficiency of U.S. wholesale natural gas and 

electricity markets from Jan. 1, 2002, through June 30, 2003 (the “assessment period”). This report fulfills the 

Commission’s commitment to Congress to provide a comprehensive assessment of energy markets that uses 

market data and performance criteria, improving the Commission’s ability to identify and correct trouble spots 

in the market before they become serious. This report also establishes a framework for performing future 

analyses of energy markets in order to better assess performance and improvements over time.

INTRODUCTION

S T A T E O F T H E M A R K E T S

3

SUMMARY

As shown in Figure 1, energy markets faced serious challenges that included an unprecedented financial downturn for 

energy traders and providers and a corresponding decline in 

the use of risk management tools, mixed incentives for energy 

investment, the slow response of natural gas production to 

increasing prices, the continuing thinness of reported market 

activity and the expansion of concerns about the transparency 

and credibility of price formation. However, energy markets 

proved sufficiently resilient to manage these challenges and 

delivered energy to customers reliably. 

Marginal improvements occurred in the way wholesale energy markets in the United States 

provided electricity and natural gas during the assessment period, despite significant challenges. 

Markets delivered energy reliably and several improvements occurred, including improvements 

in the functions of certain short-term, organized electric markets; the development of innovative 

products and services designed to improve risk management; price stabilization in the West due to increased 

generation capacity and improved hydroelectric conditions; investment that added new generating capacity 

throughout the country (increasing total U.S. capacity by 10 percent), including new efficient generation in the 

Southeast; and a focus by a broad set of market participants on the credibility of price formation. 

Across the country, prices for both electricity and 

natural gas were below 2001 levels but tended to rise during 

the assessment period, more significantly for natural gas 

than electricity. Downward pressure on electric prices early 

in the assessment period resulted from the entry of new 

generating capacity and lower demand levels than earlier, 

comparable periods. Electricity price increases appear largely 

attributable to increases in natural gas prices. 
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

4

Approach

More than a decade ago, the Commission began to 

make use of competitive market forces to the extent possible 

to benefit customers and to achieve just and reasonable 

prices.1 Well-functioning competitive markets benefit customers because they: 

 provide information about the value of energy to buyers and sellers active in the markets who, through their 

market actions, produce competitive prices,

 create incentives for efficient production,

 allocate scarce resources efficiently,

 create incentives for efficient investment where and 

when needed by highlighting scarcity through price signals, and

 provide customers with new options and flexibility for 

meeting demand.

To the extent that markets do not function adequately, 

the benefits of competition are not achieved for customers. 

To function adequately, wholesale markets need to be 

workably competitive and need to offer sufficient contracting alternatives to allow participating firms to manage 

their risk. Workably competitive markets tend to have many 

buyers and sellers participating, have no artificial barriers 

to entry and exhibit little market power or manipulation. 

Figure 1: Market events challenge natural gas/power market liquidity and credibility. 

Note: Gas Daily daily spot prices at Henry Hub provided to illustrate two years of U.S. gas commodity price behavior starting in winter 2001–02. An 

average of peak hour prices in PJM’s day-ahead market provided as an example of regional power prices.

Source: PJM, Platts Gas Daily and trade press. Graphic by OMOI.

1 Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, Order 

No. 436, Regs. Preambles 1982-1985, FERC Stats. & Regs. ¶ 30,665, order 

on reh’g., Order No. 436-A, Regs. Preambles 1982-1985, FERC Stats. & 

Regs. ¶ 30,675 (1985). 

 Pipeline Service Obligations and Revisions to Regulations Governing 

Self-Implementing Transportation Under Part 284 of the Commission’s 

Regulations, and Regulation of Natural Gas Pipelines After Partial Wellhead 

Decontrol, Order No. 636, FERC Stats. & Regs. ¶ 30,939 (1992).

 Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs 

by Public Utilities and Transmitting Utilities, Order No. 888, 61 Fed. Reg. 

21,540 (May 10, 1996), FERC Stats. & Regs. ¶ 31,036 (1996), order on 

reh’g, Order No. 888-A, 62 Fed. Reg. 12,274 (March 14, 1977), FERC Stats. 

& Regs. ¶ 31,048 (1997). 

 Regional Transmission Organizations, Order No. 2000, 65 Fed. Reg. 809 

(January 6, 2000), FERC Stats. & Regs. ¶ 31,089 (1999), order on reh’g, 

Order No. 2000-A, 65 Fed. Reg. 12,088 (March 8, 2000), FERC Stats. & 

Regs. ¶ 30,092 (2000), aff ’d sub nom. Public Utility District No. 1 of 

Snohomish County, Washington v. FERC, 272 F.3d 607 (D.C. Cir. 2001).
S T A T E O F T H E M A R K E T S

5

Prices in competitive markets tend to respond to fundamental changes in supply and demand. For this reason, 

we expect efficient competitive natural gas and electric 

markets to exhibit market prices that respond to factors 

affecting demand such as economic growth and weather, 

and to factors affecting supply such as input prices, production levels and transmission congestion. In addition, prices 

in well-functioning markets are sufficiently transparent 

for market participants to base buy and sell decisions, and 

to signal the need for new investment. Sufficiently robust 

markets show evidence of alternative products that allow 

firms to balance reliance on short-term spot markets with 

less volatile longer-term markets, or to protect themselves 

from volatility through investment or the purchase of risk 

management or hedging vehicles. We would expect the 

prices for these alternative products to converge to a point 

that reflects differences in risk among them. If a price 

differential exists for other reasons, customers in a wellfunctioning market will seek out the best value, putting 

competitive pressure on the prices of all products. 

Using these characteristics of well-functioning markets 

as a guide, this report assesses how well energy markets 

within the oversight of the Commission, or those closely 

related to those jurisdictional markets, functioned during the 

assessment period. In order to determine whether natural 

gas and electricity markets functioned in accordance with 

these factors, OMOI staff examined available evidence on 

several factors. 

First, we examined key characteristics of the structure 

of the markets and assessed their ability to support competitive performance. Staff then compared price behavior during 

the period to fundamental supply and demand drivers of 

prices, including seasonal demand, peak delivery constraints, 

storage levels, known outages, generating fuel prices and 

others. In particular, staff reviewed prices during scarcity 

conditions at certain times and locations. Staff examined 

where and how regulatory mitigation of market outcomes, 

designed to deal with perceived market imperfections, was 

administered during the period. Staff also reviewed market 

design and transparency, assessing the availability of information and the degree to which differences in market designs 

across regions or industries inhibit efficient commerce. Staff 

assessed risk management options across markets, looking 

at both the availability and use of these price and reliability 

hedging tools. Finally, staff examined investment during the 

period, assessing actual investments in infrastructure and 

supply options as well as investment signals in these markets. 

Key findings of OMOI’s analysis are presented first. 

The remainder of the report is organized into two major 

sections, one examining wholesale electric markets and 

one examining wholesale natural gas markets. Electricity 

markets are analyzed regionally and divided into two 

groups: regions with organized electricity markets—

markets operated by independent system operators (ISOs) 

or regional transmission organizations (RTOs)—and 

regions without organized electricity markets operating 

during the assessment period. Figure 2 characterizes the 

level of development of regional transmission service and 

electricity markets across the country. Approximately 120 

million Americans (40 percent of the population)2 lived in 

states served by organized markets during the assessment 

period. An additional quarter of the population lives in 

regions where organized markets are forming and will be 

operated by MISO, SPP and an expanded PJM. 

2 Derived from U.S. Census Bureau (factfinder.census.gov).
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

6

There are five regions with operating organized electricity markets assessed in this report3

: 

 ISO-NE (the New England states)

 NYISO (New York)

 PJM (much of the Mid-Atlantic states)

 ERCOT (most of Texas)

 CAISO (most of California)

There are six regions without operating organized 

electricity markets assessed in this report:

 Southeast

 Florida

 Midwest

 South Central4

 Southwest

 Northwest

Key Findings of the Report

Electricity Markets

1. Electricity markets generally performed consistent 

with supply and demand factors during the assessment period, with prices rising and falling daily 

and seasonally in response to factors such as weather, customer demand, input fuel prices and power 

plant outages. 

The relationship between prices and underlying market 

fundamental variables is complex, as we observed in the 

response of electricity markets across the country to the 

run-up of natural gas prices in late February and early March 

2003. With this notable exception, electricity prices during 

2002 were lower than in prior periods, but rose to moderately higher levels in the first half of 2003.

Organized markets delivered electricity to customers 

in 2002 at average regional prices lower than in 2001. Prices 

declined 8–15 percent, with the exception of CAISO markets, 

which declined 77 percent from 2001 levels. Milder weather, 

new generating capacity, inexpensive natural gas and 

improved hydroelectric conditions in the West contributed 

to the lower 2002 prices. Prices began to increase with the 

Figure 2: Operating or forming organized electricity markets serve 

approximately 70 percent of U.S. population.

Note: Western Kansas, which is part of the NERC SPP region, will be operated by MISO.

Source: Platts POWERmap. Graphic by OMOI.

3 For a map of these regions, see Figure 8 and Appendix 1. 4 During the assessment period, Entergy Corp. was in preliminary stages to join 

SeTrans, a proposed RTO in the Southeast. For this reason, its service territory 

was considered as part of the Southeast, not South Central. Depending on 

future activities, we may realign the regions in subsequent reports.
S T A T E O F T H E M A R K E T S

7

rise and spike of natural gas prices in late February and early 

March 2003 and remained at moderately higher levels (20–

30 percent higher than in 2001) through mid-2003. Again, 

CAISO was an exception with first-half 2003 prices nearly 

70 percent below 2001 levels. ERCOT was another exception 

with average first-half 2003 prices more than double the 

average 2001 level. Prices for bilateral transactions in these 

regions demonstrated similar trends. 

Bilateral prices outside regions with organized markets 

were reported lower in 2002 than their 2001 levels, trending 

upward in summer 2002 and during the February/March 

2003 natural gas price spike. The average first-half 2003 

prices were about 20 percent higher than 2001 levels, with 

the exception of the western trading hubs of Mid-Columbia 

and Palo Verde, where prices remained significantly below 

2001 levels.

Electricity price volatility generally declined in regions with 

organized markets, but generally increased in regions without 

organized markets. In organized markets, the exception was 

ERCOT, where volatility increased. Volatility of bilateral prices 

at Mid-Columbia in the Northwest declined in 2003, reflecting 

improved hydroelectric availability in the region. Electricity price 

volatility was higher than physical natural gas price volatility, 

which rose steadily during the period.

Lower prices resulted in losses for some power plants. 

Investors, not customers, generally bore these losses, which 

caused some short-term financial stress, but encouraged 

long-term market efficiency through investment accountability. Despite the exit and entrance of market participants, 

as well as changes in company strategies and the crisis in 

confidence during the assessment period, the electricity 

markets delivered reliable service to customers.

2. Organized markets offered new risk management 

tools during the assessment period. Market participants had few opportunities for long-term price discovery, which facilitates risk management. 

Among the most notable developments were the 

increase in risk management products offered in organized 

markets and the introduction of additional financial products 

for risk management. NYISO, ISO-NE, PJM and ERCOT 

introduced new products and services, such as firm transmission right options. Nymex began to offer new credit clearing 

products. It also introduced a redesigned PJM futures 

contract at the end of the assessment period, the use of 

which rose over time. Risk management tools were available 

bilaterally in all regions, but heightened creditworthiness 

risk and associated costs affected their use.

Despite significant reliance on long-term bilateral 

electricity contracts (approximately one-third of reported 

U.S. sales are delivered under long-term contracts of one 

year or longer), it is not clear that market participants used 

published indices for long-term products (such as Megawatt 

Daily’s prices through calendar year 2006), which could have 

provided long-term risk management. Anecdotal evidence 

suggests that parties aggregated their transactions through 

independent parties to derive long-term forward price curves 

to help determine value-at-risk for risk management controls 

and reporting. The PJM Western Hub contract remained the 

only futures market for electricity.

3. In most regions bilateral trading volumes reported to index publishers and transacted on the 

IntercontinentalExchange (ICE) declined over 

the assessment period, coinciding with merchant 

credit problems. Regions in the West were a notable 

exception to this trend. Despite overall declines in 

bilateral trading volumes, organized markets had 

robust participation during the assessment period.

The Enron bankruptcy in 2001 and later developments 

precipitated a crisis of confidence in the physical and financial electricity industry. Many companies engaged in trading 

withdrew from bilateral markets as the perceived risk and 

creditworthiness requirements increased significantly. The 

decline in the number of market participants trading actively 

led to lower liquidity in bilateral markets, and growing 

concern regarding the credibility and representativeness of 

the price data being supplied to index developers. Bilateral 

trading volumes in the West did not follow this trend, as the 

region rebounded from a collapse in trading. While overall 

trading activity fell during the period, new players emerged 

with financial backing and experience in other markets. 

Despite declines in bilateral trading volumes, participation in organized short-term markets was strong. Sales 

in regions with organized markets were approximately 

60 percent of total reported wholesale sales during the 

assessment period.5 On average, 67 percent of reported 

transactions in regions with organized markets were under 

short-term contracts (bilateral and in ISO-operated markets). 

With the exception of the California and ERCOT balancing 

markets, 20 percent or more of short-term transactions in 

regions with organized markets took place within the ISO or 

RTO short-term market. This in part reflects the availability 

of transparent organized short-term markets. It also reflects 

local supply-demand conditions. Market participants in 

5 Derived from FERC Electric Quarterly Reports (EQR), Fourth Quarter 

2002 through Second Quarter 2003. In the EQR, companies report 

wholesale power sales within FERC’s jurisdiction. Generation to serve 

one’s own load, sales by federal authorities such as TVA and BPA, sales 

occurring fully within ERCOT and sales by qualifying facilities (QFs) 

under QF contracts are not included. Filings with clear errors affecting 

total sales were eliminated from the dataset pending correction from the 

submitting company. Regional allocation of sales was estimated using 

Point of Delivery Control Area and Specific Location information provided in the filings. All sales to ISOs were assumed to be short-term and 

to occur within the ISO’s control area.
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

8

regions without organized markets reported 61 percent of 

transactions were under short-term bilateral contracts. 

4. Regions with organized markets had numerous 

buyers and sellers and the ownership of generation was spread among several entities. There were 

fewer buyers and sellers in most regions without 

organized markets and the ownership of generation 

was more concentrated in many of these regions. 

Concentration reduced competitive forces in some 

markets.

The market structures in regions with organized 

markets were relatively competitive during the assessment 

period, providing the basic conditions and support for the 

competitive performance of these markets. Load pockets 

in these regions were important exceptions to this general 

result. The market structures in regions without organized 

markets provided significantly less support for competitive 

market performance, with control of both generation and 

transmission service concentrated in a single or a few vertically integrated entities during the assessment period. 

Figure 3 shows the single largest installed and peaking 

capacity owner across regions. OMOI’s analysis of concentration of generating plant ownership found that for installed 

generation in organized markets, no single firm controlled a 

dominant share of capacity for the overall market. However, 

during peak periods and in geographically defined areas like 

load pockets, market shares tended to be higher. Many regions 

without organized markets exhibited high supplier market 

shares in both installed and peaking capacity generation. This 

is largely due to the dominance of vertically integrated utilities 

that controlled both transmission and generation services, and 

historical development of the regions. 

As a result of these findings, OMOI concludes that there 

are regions without organized markets where the basic 

conditions and market structure for achieving competitive 

performance did not appear to be in place. This is an issue 

that OMOI will continue to explore and analyze.

5. Electricity customers had better market options 

within regions with organized markets than within 

regions without organized markets. 

The fullest set of trading, scheduling and risk management products was offered in regions with organized 

markets (see Table 1; products available in natural gas 

markets are provided for comparison). The clearest advantage of organized markets for customers was the opportunity 

for buyers and sellers to trade electricity day ahead and in 

real time in open, transparent markets. 

There were major differences in the scope and depth 

of information available to customers about price formation. 

In particular, customers in regions with organized markets 

received location-specific pricing and explicit pricing of 

congestion in real time. Pricing in regions with organized 

markets was transparent to the public and monitored in 

real time by market monitors. Customers in regions without 

organized markets had significantly less market information 

about prices, price formation, system conditions and transmission infrastructure needs than their counterparts in regions 

with organized markets. Outside organized markets there was 

limited market price information regarding the value of elecFigure 3: Generation ownership concentration lower in organized markets.

Note: Installed capacity is the measured capacity or the capacity demonstrated to have been available during the hour of highest output of a generating unit. For purposes of this analysis, the working definition of a peaking unit is a natural gas or oil-fired unit with a heat rate greater than 10,000 

Btu/kWh or a combustion turbine or internal combustion unit smaller than 50 MW in size with no reliable heat rate information reported.

Source: Platts POWERdat, Modeled Production Costs-Ownership-Based dataset for calendar year 2002. Analysis and graphic by OMOI.
S T A T E O F T H E M A R K E T S

9

tricity over time and across locations or of the regional needs 

for transmission and generation siting, resulting in:

 opaque (nontransparent) prices,

 less-efficient dispatch of power plants, 

 use of less-efficient congestion management tools, and

 muted or distorted signals for investment, particularly 

where it is most needed. 

The poor quality of information outside organized 

markets limited the effective functioning of wholesale 

electric markets in those areas, potentially resulting in higher 

costs to customers.

6. Interdependence between electricity and natural 

gas markets increased, affecting prices, services 

and infrastructure requirements in both markets.

Nearly 96 percent, or 82 GW, of all generating capacity 

completed during the assessment period was gas-fired.6 As 

shown in Figure 4, natural gas-fired units—both combustion turbines and combined-cycle plants—represented the 

marginal source of electricity in several key markets including CAISO, ERCOT, much of Florida, the Northwest and 

ISO-NE. 

6 Derived from EIA, Form 860.

Table 1: Wholesale energy markets design, June 2003.

Legend:

 = Yes

 = No

 = Not market based

Regions with 

organized markets

Regions without 

organized markets

Natural 

Gas

ISONE NYISO PJM ERCOT CAISOSoutheast Florida MidwestSouth 

Central

SouthwestNorthServices Provided west

Bilateral transactions            

Active online physical trading (1)            

Real-time energy market            

Locational energy price            

Hourly energy price             (2)

Congestion price            

Losses price    (3)   (4)       

Day-ahead energy market            

Locational energy price             (5)

Hourly energy price            

Congestion price            

Losses price    (3)         

Ancillary services market            

Capacity market             (6)

Futures market            

Regional transmission scheduling            

Regional economic dispatch     (7)  (7)       

Regional transmission planning            

Regional interconnection process            

Independent market monitor            

Note: (1) An active market is defined as one that currently provides an historical price series. (2) An intra-day market for balancing physical 

natural gas operated. Prices posted on ICE during the delivery day revealed natural gas prices to customers for increments shorter than one day. 

(3) Losses are allocated to market participants based on a pro-rata share of total transmission losses. (4) Losses are allocated to sellers using 

generation meter multipliers, which reflect scaled marginal losses. (5) Gas market participants could transact for day-ahead gas. Unlike dayahead markets for electricity, day-ahead gas purchases are not broken into hour-long increments. (6) Products traded: transmission capacity in 

the pipeline capacity release market and storage capacity in the storage market. (7) CAISO and ERCOT did not have day-ahead energy markets; 

economic dispatch was used in their real-time balancing markets only. 

Source: OMOI.
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

10

Flexibility of existing services improved with the 

introduction of new services and products by the natural 

gas and power services industries, assisting electric market 

participants to reduce gas procurement costs or increase 

generating plant profits. The introduction of substantial 

new gas-fired generating capacity imposed new operational 

challenges on market participants and underscored the need 

for new services. Substantial incremental natural gas pipeline 

capacity, storage deliverability and liquefied natural gas 

(LNG) send-out capability were announced and certificated 

during the assessment period, in large part to meet the 

growing demand for gas by generators. 

Prices for natural gas were increasingly influenced by 

the demand for electricity, which accounts for 27 percent of 

total U.S. natural gas consumption.7 Because the short-run 

demand for fuel to generate electricity can be fairly price 

inelastic, this can increase gas prices. The high value of 

natural gas in power generation markets bid gas away from 

some lower-value applications, including major industrial 

users that depended on low-cost natural gas. 

7. Diverse market designs represented barriers to 

improved competitiveness and efficiency. 

Market designs across electricity markets were diverse. 

Organized electricity markets differed somewhat in product 

definitions and energy market operations, as well as in how 

they provided locational value signals and ancillary services. 

Electric markets in regions without organized markets 

depended on bilateral trading and voluntary reporting of 

price information to price index publishers to provide price 

signals to customers. These differences in market design, 

both in regions with and without organized markets, 

resulted in price seams between electricity markets, preventing efficient trading. 

Differences in operational procedures between electricity and natural gas markets also created seams, which stifled 

efficient trading. 

8. Some of the nation’s electricity markets were not 

efficiently signaling the need for infrastructure to 

meet growing energy requirements. 

Reserve margins and load data indicate that there were 

adequate, or in some cases, excess resources and reserves 

to meet regional demand during the assessment period. 

However, load pockets persisted in subregions where the 

capability to import lower-cost power was significantly 

constrained. Moderate amounts of investment were made, 

but often not in the locations where it was most needed. 

Figure 4: Natural Gas is the marginal fuel in many regions.

Note: Percent of time gas or oil was projected to have been on the margin during peak hours in 2003.

Source: Cambridge Energy Research Associates (CERA). The use of this graphic was authorized in advance by CERA. No reuse or redistribution of 

CERA information is permitted without written permission by CERA. For more information contact CERA at (617) 866-5992.

7 EIA, Natural Gas Navigator, “U.S. Total Natural Gas Consumption by End 

Use,” 2002 annual data, (tonto.eia.doe.gov/dnav/ng/ng_cons_sum_nus_a_

d.htm). 
S T A T E O F T H E M A R K E T S

11

Financial requirements for raising capital for new 

investment increased sharply and, coupled with lower 

wholesale market prices than in previous years, this resulted 

in the slowdown or cancellation of several announced 

projects. OMOI’s analysis indicates that net revenues 

generated during the assessment period would not have 

been sufficient to cover total costs of operating plants or to 

attract new investment in supply or demand in many of the 

regions examined. This was appropriate in regions that 

have adequate reserves, but stronger and clearer price 

signals were needed in several load pockets. In addition, 

OMOI observed that bid mitigation may have dampened 

the price signals markets provided for new investment 

needed in load pockets.

Declines in the creditworthiness of several large market 

participants, which increased financing costs, drove up the 

costs of new investment. Lower credit ratings had implications not only for capital costs, but also for the liquidity and 

collateral requirements for trading and marketing in the 

futures and physical power and gas markets. Heightened 

collateral requirements and changes in how rating agencies 

assess the risk of power trading led to higher explicit or 

implicit equity support needs for these activities. This ultimately resulted in reduced electricity and natural gas trading 

and the exit of several participants. New players began 

to emerge with the resources to make new investments; 

however, they required more certainty about market rules 

and expected revenue streams than in the past.

9. Demand response would have been cost-effective in 

some key locations. 

Demand response, an effective tool for dampening 

price spikes and protecting reliability, was largely missing 

from electricity markets during the assessment period. 

Because lack of demand responsiveness to price harms 

competitive wholesale markets, demand response must 

offer the customer an attractive proposition. In contrast to 

regions with organized markets, wholesale prices in regions 

without organized markets reflected day-to-day and seasonal 

changes, but not the real-time changes in prices that reflect 

the time-varying cost of producing electricity. Regardless 

of market design, however, most end-use customers in all 

regions were not aware of—and had no means to be aware 

of—the hourly, daily and seasonal changes in the wholesale 

costs of providing service to them. 

A small percentage of customers had meters that 

measure usage close to time of use, and even fewer receive 

information directly about the prices prevailing in wholesale 

markets. Demand response in organized markets was 

successful in attracting some customers and had some 

measurable effects on market-clearing prices. However, the 

development of demand response resources was limited. 

Given the relatively low energy prices during the assessment period, hypothetical customers would have found low 

or no net benefits from a hypothetical demand reduction 

in most regions of the country if they were dependent on 

energy bill savings alone. However, energy savings would 

have been sufficient to make demand reduction cost-effective for a demand responsive customer in New York City. 

Additional savings or revenues from demand response 

markets or sale of ancillary services or capacity reserves 

made demand reduction cost-effective in key load pocket 

locations in Southwest Connecticut and the Delmarva 

Peninsula in PJM.

Natural Gas Markets

1. Natural gas prices during the assessment period 

generally behaved consistent with the fundamental 

forces of demand, supply and seasonality, but the 

market faced challenges. 

The natural gas market exhibited characteristics of a 

well-functioning market by delivering products on time to 

customers and spurring reasonable levels of investment. 

Limited production and severe weather during the assessment period tightened supplies, which in turn led to higher 

prices, greater price volatility and severe swings in storage. 

In markets for financial transactions, the volume of trades 

decreased, a problem exacerbated by the erosion of credit 

quality among trading entities, including the bankruptcy 

of some merchant firms. Price transparency was further 

clouded by events that brought the credibility of the price 

indices into question.

As evident in Figure 5, average spot and forward market 

prices exhibited a significant upward shift in the past three 

years, reflecting tight supplies and tight storage conditions. 

Natural gas spot prices at Henry Hub escalated steadily 

through the assessment period, rising from $2/MMBtu in 

January 2002 to $6 in January 2003, then spiking briefly 

in February 2003 to $19 before quickly returning to the 

$6 range from March through June 2003. Futures prices 

indicate the magnitude of the shift in general price levels. 

The average next-month price was $2.04 from June 1990 

through December 1999, but it more than doubled between 

January 2000 and June 2003, rising to $4.18. 
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

12

Customers responded to higher prices, as appropriate in an efficient market. Industrial and power customers 

reduced natural gas use 5.6 percent and 13.0 percent, 

respectively, between the first half of 2002 and first half 

of 2003, while the residential and commercial sectors 

increased consumption in response to weather conditions and continued growth. A full assessment of the 

consequences of higher natural gas prices and their effect 

on the national economy and customers was beyond 

the scope of this study, but there is concern that higher 

natural gas prices are driving some industrial production 

out of the United States and reducing disposable income 

for customers.

Supply tightness, and concern about this tightness, 

came from a 3.2 percent reduction in production in 2002, 

declining well productivity, uncertainty about whether 

production increased or decreased in 2003, reduced 

imports (while LNG imports increased dramatically, lower 

imports of natural gas via pipeline from Canada more 

than offset LNG’s gains), increased exports to Mexico 

and continued land access restrictions. At the same time, 

as shown in Figure 6, storage inventory shifted from 

abundant in November 2002 to the low end of the fiveyear range in March 2003. Uncertainties about whether 

storage could be adequately replenished helped boost 

natural gas prices through summer 2003. 

Figure 5: Monthly natural gas prices peak in late-winter 2002 and remain high through following summer.

Source: Platts Gas Daily and ICE. Analysis and graphic by OMOI.
S T A T E O F T H E M A R K E T S

13

2. Market participants’ capacity to manage price volatility weakened, primarily because of the increase 

in credit risk during the assessment period. 

During the assessment period, the volatility for nextday physical prices at Henry Hub rose, and both the price 

level and price volatility were higher on average than in 

any period during the early 1990s. Methods to reduce 

exposure to price volatility included the use of storage, longterm fixed-price physical contracts, firm pipeline capacity 

contracts and financial contracts. 

Reduced market liquidity weakened the ability of 

market participants to manage volatility. The loss of liquidity stemmed from the lower number of participants in the 

market (due to bankruptcies and withdrawals) and possibly 

from fewer trading positions per company. Underlying these 

trends were increased credit risk and default risk. This in 

turn led to difficulty finding creditworthy counterparties, a 

decrease in the amount of counterparties willing to transact 

long-term structured contracts and a decline in industry 

confidence. There were also reported increases in bid-ask 

spreads, another indication of credit strains and lower 

market liquidity. 

3. New participants and new products demonstrate 

that the market gained efficiency as it addressed 

the credit problems that hindered its effectiveness 

during the assessment period.

Existing and new industry players, typically with 

stronger credit ratings, entered the marketing and trading 

segments of the industry, partially filling the void left by 

the exit of many merchant energy companies prior to the 

assessment period. New marketing and trading participants 

included marketing affiliates of producers, LDCs and financially oriented firms, such as large banks and hedge funds. 

In 2002, Nymex and ICE introduced new products for 

credit clearing that enable participants to manage credit 

risk by transferring the counterparty credit risk in bilateral 

transactions to the clearing organization. Market participants actively purchased these products, but high margin 

requirements and limited credit capacity inhibited some 

participation. 

Figure 6: Storage use pushes upper and lower capacity limits.

Source: EIA. Analysis and graphic by OMOI.
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

14

4. The physical natural gas market coped with 

imperfect transparency and eroded credibility, 

while the financial markets provided forward price 

transparency through several robust indicators.

The quality of price information available to physical 

market participants varied because the lack of liquidity and 

transparency inhibited price discovery at many of the trading 

points outside of the most well known, such as Louisiana’s 

Henry Hub, an active physical-market trading point as well 

as the delivery point for Nymex gas futures contracts. As a 

result, physical markets were highly dependent on indices 

assembled from information provided by market participants 

who voluntarily reported to index publishers and indices 

based on exchange-conducted transactions. 

Enron’s late-2001 declaration of bankruptcy, allegations 

of misreporting by traders to the index publishers and revelations of wash trading in April 2002 undermined credibility 

of indices. The credibility problem and corresponding 

changes in industry participant business strategies caused the 

volumes of transactions reported to index providers to fall 

sharply during the assessment period.

Efforts to restore confidence in indices and thereby 

enhance price discovery have been multifaceted. Industry 

groups developed and proposed best practices,8 while 

index developers increased the market participants’ ability 

to examine liquidity factors and market trends at multiple 

locations by categorizing each location by “tiers” that indicated the volume of transactions. ICE began publishing the 

number of counterparties and number of transactions per 

location traded on its system. 

Nevertheless, physical market price discovery continued 

to be a problem. Many participants did not report to index 

providers or did not report on all trading points. While the 

entire market benefits from all participants reporting transactions, individual participants may see no individual benefit 

in submitting all their transactions to an index provider, a 

factor that may discourage reporting. 

8 FERC issued a policy statement reflecting a consensus on ways to improve 

the current voluntary price reporting system and conducted a survey in 

October 2003 to determine whether, how and to what extent market participants reported price data to index developers. 

Figure 7: 2003 producer drilling response to high prices is moderate.

Note: Prices not adjusted for inflation.

Source: Platts GASdat, Platts Gas Daily and Baker Hughes. Analysis and graphic by OMOI.
S T A T E O F T H E M A R K E T S

15

Prices in forward months are necessary for participants 

planning hedges and making investment decisions. During 

the assessment period, forward price transparency was available through the Nymex Henry Hub futures contract, which 

offered prices out for six consecutive years. Forward price 

transparency at locations other than Henry Hub were available for shorter periods of time. Forward price transparency 

improved during the assessment period with the introduction in 2002 of financial OTC swaps on Nymex’s ClearPort 

system. 

5. The investment response to higher prices was moderate, but price signals for needed investment were 

reasonably strong.

Forward price expectations increased in 2003, sending 

signals to investors that higher natural gas prices might be 

sustainable and additional investment justified. 

Despite strong price signals, the supply response did 

not fully temper tightness in the overall North American 

supply and demand balance. A moderate increase in gasdirected drilling and diminishing recoveries per natural gas 

well completed appeared to mute the new domestic natural 

supply response. As shown in Figure 7, the drilling rig count 

did not reach levels achieved after the 2001 price spike. 

Factors contributing to this moderate response included 

drilling companies’ efforts to strengthen their balance sheets, 

avoid creating a glut in production and avoid investments in 

marginal prospects. 

In response to the supply outlook and to FERC’s change 

in policy regarding LNG facilities, developers proposed 

more than 30 LNG receipt terminals in North America to 

supplement domestic supplies. As is the case for other capital 

intensive projects, the number of LNG projects that will 

actually be built will be less than those planned because 

investors must overcome pricing, contracting, siting, permitting and other concerns to secure financing, successfully 

execute construction and operate. Even if successful, new 

LNG investment will not substantially augment short- to 

medium-term natural gas deliverability because new facilities 

require years to complete.

Investment in new storage capacity was low, increasing 

0.3 percent (23 Bcf) from 2001 to 2002. The slow rate of 

capacity additions reflects the many challenges to storage 

investment, including locating, acquiring and developing a 

suitable storage site, regulatory delay and financial and credit 

issues. For non-traditional, high-deliverability storage with 

higher development costs, the economics are dependent 

upon projecting trading benefits from volatility via “real 

options” or other techniques, in addition to the traditional 

seasonal arbitrage. Unfortunately, the advantages of trading 

around volatility or real option value are difficult for lenders 

and investors to quantify, especially with the decreased 

9 A basis differential is the difference between a natural gas price point (e.g., 

a market hub, citygate or supply receipt area) and a reference point, most 

often Henry Hub. During periods of low pipeline capacity utilization, the 

basis differential will reflect the variable costs of transportation and typically 

be below the 100 percent load factor pipeline tariff rate in an efficient natural gas market. As capacity constraints develop, the basis differential will 

reflect regional supply and demand conditions in a market and, depending 

on the severity of the constraint, the basis may exceed the cost-based tariff 

rate for transmission capacity, occasionally by large multiples. Consistently 

and sufficiently high basis differentials signal continued constraints and the 

need for new pipeline capacity. 

activity in the wholesale trading sector and corresponding reduced liquidity. Substitutes for storage (e.g., new 

pipeline capacity, remarketed pipeline capacity and financial 

products) also compete with increased storage investment. 

Pipeline investment appeared to be appropriate given 

basis signals. Before market participants contractually 

commit to a project, forward market basis values or swaps 

along key pipeline corridors must signal that added capacity 

is needed and likely to be profitable.9 The level of pipeline 

completions grew steadily through 2002, with indications 

that 2003 investment was slightly lower. Some pipeline 

projects were delayed or cancelled. This was primarily 

because many projects remained economically marginal, 

especially in light of changing business conditions and the 

difficulty of obtaining long-term contracting due to a lack of 

shipper commitments and/or shipper creditworthiness. 

Longer term, FERC certificated 2,234 miles (7.4 Bcfd) 

of pipeline during the assessment period, indicating that 

companies are planning to continue to invest. OMOI analysis 

of financial basis differentials in the Rockies and San Juan 

basin for example, suggest that price signals justify new 

pipeline construction within the next two years. In contrast, 

the differential from Henry Hub to Transcontinental Gas 

Pipe Line Corp.’s (Transco’s) Zone 6-NY provides partial 

market signals supporting investment in the future, but does 

not fully support new construction from the Gulf of Mexico.

S T A T E O F T H E M A R K E T S

17

T

he Commission’s ability to assess the performance of electric markets varied substantially across the 

United States as well as across electricity services and products. In most cases, more information 

about the formation of short-term market prices was available in regions where Commissionapproved organized markets—ISOs or RTOs10—operated than in regions where they did not. 

Long-term price information was limited in all regions. During the assessment period, regions with operating 

organized markets were ISO-NE, NYISO, PJM, ERCOT and CAISO. Regions without operating organized markets 

were the Southeast, Florida, the Midwest, South Central,11 the Southwest and the Northwest. These regions are 

shown in Figure 8. 

ELECTRICITY

MARKET

PERFORMANCE

10 An RTO is an independent entity approved by FERC to provide nondiscriminatory wholesale electric transmission service under one tariff for a large 

geographic area. To be approved by the Commission, an RTO must meet 

four characteristics and perform eight functions listed in Order 2000. The 

four characteristics are independence from market participants, appropriate scope and regional configuration, operational authority over the regional grid and responsibility for short-term reliability. The eight functions are 

tariff administration, congestion management, management of parallel path 

flow, provision of ancillary services, provision of transmission information 

through OASIS and calculation of available transfer capability (ATC), market monitoring, planning and expansion and interregional coordination. 

Similar to an RTO, an ISO is an independent entity that has been approved 

by FERC to provide nondiscriminatory wholesale electric transmission service under one tariff. An ISO must satisfy 11 ISO principles listed in Order 

888, that require fair and nondiscriminatory governance, independence 

from financial interests of participants, open access under a grid-wide 

tariff, control over operation and short-term reliability, efficient pricing 

and congestion management, public and timely availability of transmission 

information and coordination with neighboring regions. Though somewhat 

different in scope and function, RTOs and ISOs are similar in that the 

Commission grants them the authority to operate, in a nondiscriminatory 

manner, the transmission assets of participating transmission owners in a 

fixed geographic area. They also often operate short-term markets designed 

to optimize generation costs. Some ISOs and RTOs operate both real-time 

and day-ahead markets to balance the forecasted volumes with the volumes 

actually consumed. 11 During the assessment period, Entergy Corp. was in preliminary stages to 

join SeTrans, a proposed RTO in the Southeast. For this reason, its service 

area was considered as part of the Southeast, not South Central. Depending 

on future activities, we may realign the regions in subsequent reports. 
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

18

In both regions with and without organized markets, 

short-term bilateral markets exist.12 These are primarily 

day-ahead markets, which are forward markets for electricity 

to be supplied the following day. In regions with organized 

markets, additional day-ahead markets have developed, as 

have real-time markets. Organized day-ahead markets are 

short-term forward markets that settle or determine the 

price for one-hour periods for delivery the next day. Realtime markets are spot markets involving physical delivery on 

the operating day that typically determine prices for shorter 

time-periods (e.g., 5 or 10 minutes), even though an hourly 

average price may be published for settlements. During 

the assessment period, ISOs and RTOs did not operate 

markets for longer-term electricity transactions. All long-term 

contracting was conducted bilaterally. Table 2 summarizes 

the key characteristics of wholesale electricity markets as 

operated during the assessment period.

Figure 8: Map of electricity regions assessed.

Note: Regional maps are located in Appendix 1.

Source: OMOI.

12 The bilateral market is a combination of bilaterally negotiated contracts 

for energy and purchases of transmission and ancillary services under 

regulated tariff rates. In many regions of the country, the energy commodity is packaged with ancillary and transmission services provided by the 

same seller. A bilateral physical energy transaction is a contract to deliver 

a specified number of MWs to a specified location (or trading point) for 

a specified period of time. The terms of the contracts need not be standardized, although a prototype or master wholesale power agreement 

has been developed and gained widespread use by the industry in recent 

years (Edison Electric Institute and National Energy Marketers Association, 

Master Power Purchase and Sale Agreement, 2000). The bilateral contract 

may provide for delivery of power the next day, for several days, a month, 

multiple months, a year or multiple years. In the most basic form of a bilateral market, companies identify, evaluate, select and contract with bilateral 

trading partners based on individual relationships and processes. 
S T A T E O F T H E M A R K E T S

19

Table 2 illustrates that market options for customers were quite different between regions with organized 

markets and regions without organized markets. The clearest 

advantage was the opportunity for customers within regions 

with organized markets to purchase day-ahead or real-time 

energy in open, transparent markets that provided explicit 

information on the locational price of energy, congestion 

and losses. These regions also provided markets and public 

market prices for competitive provision of several ancillary 

services and capacity reserves. 

Wholesale customers generally purchase electricity 

products for four basic purposes: 

 to secure power for delivery at the time and location of 

their choice, 

 to minimize exposure to under- or over-estimating their 

expected demand at a future time, 

 to minimize exposure to fluctuations in the prices of 

electricity, underlying fuels and transmission congestion, and

 to take advantage of market deals that are more economic than self-generation. 

A variety of short-term and long-term physical and 

financial products can achieve these objectives efficiently; 

Figure 9 represents a list of products used to manage the 

physical delivery of electricity and the associated risks.

Table 2: Wholesale electric market products.

Legend:

 = Yes

 = No

Bilateral 

transactionsReal-time 

market

Day-ahead 

market

Ancillary 

services

markets

Capacity 

market

Active physical 

day-ahead ICE 

market

Futures

market

Financial 

trans-mission rightsVirtual 

bidding

OTC 

financial

products

Regions 

with 

organized 

markets

ISO-NE  * * * * (2)   * * 

NYISO  * * * * (2)   * * 

PJM  * * * * (2)  * * 

ERCOT  *  *    *  

CAISO  *  *    * 

Regions 

without 

organized 

markets

Southeast     (1)   (3)

Entergy

    (3)

Entergy

Florida     (1)      

Midwest     (1)       (3)

Cinergy

South 

Central     (1)      

Southwest     (1)      

Northwest     (1)      

Notes: *Designates a market operated by an ISO. (1) Ancillary services were provided at cost-based tariff rates or negotiated bilaterally. (2) ISO 

conducts an auction-based capacity market. Bilateral contracts and self-supply were also allowed. (3) Whereas products were available more widely 

within other regions, products were only available for a single price point in this region.

Source: OMOI.
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

20

In a market system, market participants bear the risks 

of supply and demand fluctuations. Investors bear the risks 

of quantity, type, location and final cost of investments. 

Customers should be able to contract for some of their 

electricity needs in advance of the time of delivery and 

consumption, just as they are able to do with other products. 

Likewise, they should be able to procure other products 

at or very near to the time of delivery and consumption. 

Further, they should be able to purchase products that 

allow them to manage a variety of risks—that they may not 

accurately forecast their demand when entering into an 

advance contract, that prices will change or that prices will 

be volatile. Incomplete markets (those that lack some of 

the products depicted in Figure 9) raise costs to customers 

because risks and uncertainty are not efficiently shifted to 

those willing to undertake them for potential profit. Longterm contracting, for example, may have benefited from 

more complete market options during the assessment period. 

Approximately 28 percent of reported U.S. sales13 were delivered under long-term contracts of one year or longer, but 

long-term electricity markets offered limited forward price 

transparency to facilitate this contracting. Similarly, longterm contracting for set volumes is facilitated by a balancing 

market or spot market to fill the gap between forecasted and 

actual demand. However, customers in several regions did 

not have access to a competitive balancing market during the 

assessment period.

The development of organized markets has not been 

uniform across the United States (see Figure 2). One reason 

that some regions have not progressed in development 

of open markets is the existence of indigenous low-cost 

resources. As seen in Figure 10, regions with low percentages 

of indigenous low-cost hydroelectric and coal resources 

tended to have organized markets in place. This is in 

contrast to regions with high percentages of indigenous 

low-cost resources, which tended to stay in traditional 

regulated structures. 

Figure 9: Physical and financial power markets work efficiently in tandem.

Source: OMOI.

13 Derived from FERC EQR, Fourth Quarter 2002 through Second 

Quarter 2003. For more information on EQR data used in this report 

see footnote 5.
S T A T E O F T H E M A R K E T S

21

We have observed that reported electricity prices over 

the assessment period generally behaved in accordance with 

observed forces of supply and demand, a key characteristic of 

competitive markets. While prices have shown volatility, price 

movements were consistent with drivers like electric demand 

and fuel costs. Consequently, while this section establishes 

the basis for these findings, we also consider factors that may 

limit the competitiveness and efficiency of markets, including 

local market power, transparency, barriers to entry, development of associated risk management markets and adequacy 

of price signals and market structure to create appropriate 

incentives for investment.

We have organized this electricity section into five parts:

 Market Structure

 Prices, Market Activity, Congestion and Mitigation

 Market Design and Price Transparency

 Risk Management

 Infrastructure Investment

Market Structure

Conventional economic analysis posits that market 

performance is a function of market structure. The 

characteristics of an electric market’s structure that are the 

subject of Commission observation and analysis include:

 the number of buyers and sellers active in the market, 

 concentration of ownership of generation,

 the extent of vertical integration of market participants, and 

 barriers to market entry. 

In particular, vertical market power (control of transmission) and horizontal market power in generation are 

two main concerns. The Commission has deemed electric 

transmission non-competitive and has employed forms of 

cost-based regulation to protect customers from the exercise 

of vertical market power in transmission service. However, 

more than a decade ago the Commission began to make use 

of competitive market forces to the extent possible to achieve 

just and reasonable prices for wholesale sales and purchases 

of electric power.14

Figure 10: Regions in organized markets tended to have low shares of indigenous low-cost generation resources.

Source: Platts POWERdat, Modeled Production Cost-Ownership-Based dataset from EIA Form 906, EIA Form 759 and FERC Form 423. Analysis and 

graphic by OMOI.

14 See Footnote 1. 
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

22

Table 4: Electricity volumes transacted in organized markets.

000 GWh 

(cumulative) Day-ahead market Real-time market

Region 2001 2002 2003 thru 

6/30/03 2001 2002 2003 thru 6/30/03

ISO-NE (1) (1) 11 (2) 30 41 8 (2)

NYISO 161 162 77 3 1 2

PJM 42 104 60 57 119 67

ERCOT (3) N/A N/A N/A 1 7 5

CAISO (4) N/A N/A N/A 14 2 1

Notes: (1) Day-Ahead Market initiated March 1, 2003. (2) Only includes transactions from March 1 to June 30. In addition, after March 1, 2003 the 

real-time market was only a residual market. (3) ERCOT does not have a day-ahead market. Real-time energy balancing market began July 31, 2001. 

Real-time market data are for real-time Balancing Up energy. (4) CAISO does not have a day-ahead market. 

Real-time market data are for Incremental (INC) energy. 

 Source: ISO websites and ISO MMU response to OMOI data requests. 

The courts have held that the Federal Power Act allows 

for market-based pricing only if the markets are competitive. 

“When there is a competitive market the FERC may rely upon 

market-based prices in lieu of cost-of-service regulation 

to assure a ‘just and reasonable’ result.”15 Additionally, the 

courts have found that “[i]n a competitive market, where 

neither buyer nor seller has significant market power, it is 

rational to assume that the terms of their voluntary exchange 

are reasonable, and specifically to infer that price is close 

to marginal cost, such that the seller makes only a normal 

return on its investment.”16 

Number of Buyers and Sellers

Generally, regions with organized markets had 

numerous buyers and sellers and the ownership of 

generation was spread among several entities, primarily 

independent power producers. Market participation by 

buyers and sellers was less in regions without organized 

markets and ownership of generation was more concentrated. These two elements of market structure are 

examined in more detail in turn.

Table 3: Number of wholesale buyers and sellers in organized markets.

Region Wholesale Buyers 

and Sellers Generators only

ISO-NE 230 46

NYISO 216 67

PJM 251 25

ERCOT 140 64

CAISO 82 N/A

Source: ISO websites and ISO market monitoring unit (MMU) response to OMOI data requests. 

There were hundreds of participants in organized 

markets, as indicated in Table 3.

Most generators and wholesale customers in these 

regions participated in the ISO or RTO markets, although 

the level of reliance varied. For example, approximately 50 

percent of all wholesale transactions in New York reported 

to FERC took place in its ISO markets, whereas market 

participants reported that use of the CAISO balancing 

markets represented about 1 percent of their total energy 

transactions.17 The amount of energy traded in organized 

markets during the assessment period was significant and, as 

indicated by Table 4, appears to be growing.18

Figure 11 presents the average and highest number of 

counterparties trading on ICE daily at six bilateral trading 

hubs. The number of counterparties trading natural gas at 

Henry Hub is shown for comparison. The Cinergy trading 

hub in the Midwest was ICE’s most active bilateral electricity trading point in the country during the assessment 

period, although the number of counterparties was still 

low compared to the number of counterparties in organized markets. A relatively large number of counterparties 

were active at this hub, with significantly fewer in the other 

regions without organized markets. 
S T A T E O F T H E M A R K E T S

23

Source: ICE. Analysis and graphic by OMOI.

Reported trading activity in the other regions without 

organized markets was significantly less than at Cinergy, as 

can be seen in Table 5. Indeed, the level of reported trading 

activity at the Florida and SPP North trading hubs was not 

indicative of a liquid market.

Figure 11: Cinergy electricity trading on ICE reaches Henry Hub gas liquidity.

15 Elizabethtown Gas Co. v. FERC, 10 F.3d 866, 870 (D.C. Cir. 1993) 16 Tejas Power Corp. v. FERC, 908 F. 2d 998, 1004 (D.C. Cir. 1990) 17 Derived from FERC EQR, Fourth Quarter 2002 through Second Quarter 

2003. For more information on EQR data used in this report see footnote 5. 18 As discussed in more detail in the examination of market performance and 

prices, the apparent decline in volumes traded in the CAISO and NYISO 

real-time markets from 2001 to 2002 appear consistent with the design and 

purpose of these markets—to balance differences between predicted and 

actual consumption. 

Table 5: Reported electricity volumes transacted bilaterally. 

Average daily volume (GWh)

2001 (full year) 2002 (full year) 2003 (first half)

Regions with organized 

markets

ISO-NE MWD 48 14 10

ICE 12 26 11

NYPP ZG MWD 11 8 3

ICE* N/A N/A N/A

PJM MWD 111 77 32

ICE 66 129 66

ERCOT MWD 34 34 12

ICE 7 15 8

NP-15 MWD 10 21 17

ICE 7 31 29

Regions without 

organized 

markets

Entergy MWD 69 54 13

ICE 43 73 30

Florida MWD 1 2 0

ICE* N/A N/A N/A

Cinergy MWD 180 127 61

ICE 128 193 130

SPP North MWD 6 5 0

ICE* N/A N/A N/A

Palo Verde MWD 17 22 11

ICE 10 32 22

Mid-Columbia MWD 16 20 16

ICE 6 42 33

Note: *ICE did not report trade volumes for day-ahead power for NYPP ZG, Florida or SPP North. Megawatt Daily volumes reflect on-peak transactions 

surveyed by the trade publication. Megawatt Daily data have been modified to make them comparable to ICE data. Megawatt Daily volumes have been 

multiplied by 16 to convert from a 16 peak-hour MW contract into a MWh. Final volumes are converted to GWh. In addition, since Megawatt Daily volumes include both buy and sell sides of transactions and ICE volumes include only the sell side of transactions, ICE volumes were doubled.

Source: Platts Megawatt Daily and ICE.
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

24

Market Concentration 

and Vertical Integration 

High levels of concentration in generation ownership 

and sales are an indicator of the potential to exert market 

power in a region, creating inefficiency and raising prices 

to customers. Figure 12 shows the largest market share 

of generation19 in each organized market for 2002. This 

comparison shows that no one firm controlled a dominant 

share of total installed generation capacity in any region 

with organized markets. However, concentration in peaking 

capacity appears higher. 

ISO-NE, for example, had a relatively competitive 

market structure with ownership of generation spread across 

several entities.20 Referring to the two left-hand columns of 

Figure 13, the 10 owners of the largest shares of generation 

accounted for 70 percent of total generating capacity in the 

region but no single entity controlled more than 20 percent 

of total installed capacity or the MWh produced.21

Only one vertically integrated utility (transmission 

owner that owns generation capacity and provides distribution services) was among the top 10 generation owners, and 

55 percent of its generation was owned by the utility. The 

remaining 45 percent was owned by a non-regulated affiliate. Two entities, both non-utilities, owned greater than a 20 

percent share of peaking capacity and had greater than a 20 

percent share of the peaking MWh generated. Comparison of 

the ownership shares with the corresponding share of energy 

produced by the entity indicates that the share of energy 

sold by an entity within a region with an economic dispatch 

process was not necessarily proportional to ownership.

Figure 12: Capacity market share lower in organized markets.

19 The regional market share calculations in this section are of gross capacity 

installed and MWh generated and are not adjusted for generation used to 

meet obligations for operating reserves, retail service or long-term contracts. The treatment of these factors, among others, is under consideration 

by the Commission in Docket No. PL02-8-000 regarding a Conference on 

Supply Margin Assessment. 20 Entities are identified by type: Vertically Integrated Utility (VIU), 

Independent Power Producer (IPP), Municipal utility (Muni), federal power 

administration (Federal), cooperative utility (COOP), other type of public 

power agency (Pub Auth). The number assigned to an entity represents 

ranking within the region being examined, and does not track to any other 

region. 21 For purposes of this analysis, markets with a single entity owning 20 

percent or less of the generation are considered to exhibit low levels of 

concentration, shares of 20 to 35 percent are considered moderately concentrated and those with shares above 35 percent are considered highly 

concentrated. 

Note: Installed capacity is the measured capacity or the capacity demonstrated to have been available during the hour of highest output of a generating unit. For purposes of this analysis, the working definition of a peaking unit is a natural gas or oil-fired unit with a heat rate greater than 10,000 

Btu/kWh or a combustion turbine or internal combustion unit smaller than 50 MW in size with no reliable heat rate information reported.

Source: Platts POWERdat, Modeled Production Costs-Ownership-Based dataset for calendar year 2002. Analysis and graphic by OMOI.

As previously mentioned, within the relatively 

competitive structures of the organized markets, there 

were peak periods and locations where concentration 

of generation ownership was higher. In New York, for 

example, as seen in Figure 14, one company controlled 

a significant portion of peak period capacity, but just 18 

percent of total installed capacity.
S T A T E O F T H E M A R K E T S

25

Figure 14: New York peaking generation concentration high.

Figure 13: Multiple companies own New England generation.

Note: Installed capacity is the measured capacity or the capacity demonstrated to have been available during the hour of highest output of a generating unit. For purposes of this analysis, the working definition of a peaking unit is a natural gas or oil-fired unit with a heat rate greater than 10,000 

Btu/kWh or a combustion turbine or internal combustion unit smaller than 50 MW in size with no reliable heat rate information reported. MWh 

produced is the net generation of an electric generating unit, or the amount of gross generation less the electrical energy consumed at the generating 

station(s) for station service or auxiliaries. Electricity required for pumping at pumped-storage plants is regarded as electricity for station service and 

is deducted from gross generation.

Source: Platts POWERdat, Modeled Production Costs-Ownership-Based dataset for calendar year 2002. Analysis and graphic by OMOI.

Note: Installed capacity is the measured capacity or the capacity demonstrated to have been available during the hour of highest output of a generating unit. For purposes of this analysis, the working definition of a peaking unit is a natural gas or oil-fired unit with a heat rate greater than 10,000 

Btu/kWh or a combustion turbine or internal combustion unit smaller than 50 MW in size with no reliable heat rate information reported. MWh 

produced is the net generation of an electric generating unit, or the amount of gross generation less the electrical energy consumed at the generating 

station(s) for station service or auxiliaries. Electricity required for pumping at pumped-storage plants is regarded as electricity for station service and 

is deducted from gross generation.

Source: Platts POWERdat, Modeled Production Costs-Ownership-Based dataset for calendar year 2002. Analysis and graphic by OMOI.
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

26

Although no single entity owned more than a 20 

percent share of total installed capacity or energy produced, 

one entity, a vertically integrated utility with non-utility 

affiliates, owned 43 percent of the peaking capacity in the 

region and generated 62 percent of the peaking MWh. This 

is a serious concern because the capacity of this entity was 

the pivotal supply in the significant load pockets of New York 

City and Long Island.22

Nevertheless, pivotal supplier tests performed by the 

market monitoring units (MMUs) of the ISOs and RTOs 

show declines in market concentration in some organized 

ISO markets as market concentration was diluted by new 

entrants. In New England for example, while there were a 

significant number of hours during the assessment period 

during which pivotal suppliers existed, the average residual 

supply index (RSI)23 improved since the opening of the 

ISO markets in May 1999.24 Nevertheless, the RSIs in load 

pockets such as Southwest Connecticut and NEMA/Boston 

areas revealed significantly more hours during which pivotal 

suppliers existed than was indicated by the system-wide 

measures.25

In California, there were pivotal suppliers in about 6 

percent of hours in 2000 and 12 percent of hours in 2001. In 

2002, which is within the assessment period, suppliers were 

pivotal in less than 0.1 percent of hours. CAISO measures 

pivotal supplier conditions through use of an RSI. CAISO’s 

Department of Market Analysis (DMA) has recommended 

accounting for “possible collusion” by adding a 10 percent 

margin to the residual supply screen for pivotal suppliers, 

which increases the hours with pivotal suppliers. Using this 

assumption results in pivotal suppliers in 20 percent of hours 

in 2000, 36 percent of hours in 2001 and 1.4 percent of 

hours in 2002.26

Appendix 3 details the pattern of generation ownership 

in the remaining regions with organized markets. 

In contrast to the organized markets, many regions 

without organized markets exhibited few buyers and sellers 

(as approximated by trading volumes) and high concentration of generation ownership by transmission owners and 

control area operators. As shown in Figure 15, many of these 

regions exhibited high market shares for the single largest 

owner in both installed and peaking capacity generation 

markets, largely because of the dominance of vertically integrated utilities and the historical development of the regions. 

Figure 15: High generation ownership shares in regions without organized electricity markets. 

Note: Installed capacity is the measured capacity or the capacity demonstrated to have been available during the hour of highest output of a 

generating unit. For purposes of this analysis, the working definition of a peaking unit is a natural gas or oil-fired unit with a heat rate greater than 

10,000 Btu/kWh or a combustion turbine or internal combustion unit smaller than 50 MW in size with no reliable heat rate information reported.

Source: Platts POWERdat, Modeled Production Costs-Ownership-Based dataset for calendar year 2002. Analysis and graphic by OMOI.

22 The entity, KeySpan Corp., has recently added a new generating unit in 

Queens increasing the company’s total electric generation capacity by 12 percent. KeySpan is also seeking approval to build two additional power plants 

on Long Island. KeySpan Corp., Jan. 6, 2004. 23 Residual supply is the amount of generation capacity remaining in the market, after subtracting the capacity of the largest supplier. If RSI exceeds 100 

percent, this indicates that the alternative suppliers have sufficient capacity to 

meet demand without the largest supplier, who is thus presumed to have relatively little influence on the market-clearing price for a given hour. However, 

if the RSI is below 100 percent, this indicates that the largest supplier’s capacity is needed to meet market demand and the supplier is considered pivotal 

in determining the market-clearing price for that hour. 24 ISO New England Inc., Annual Markets Report May–December 2002, 

Aug. 13, 2003. 25 Data response from ISO-NE MMU. 26 Data response from CAISO-DMA, and “Predicting Market Power Using the 

Residual Supply Index,” Presentation to FERC Market Monitoring Workshop, 

Anjali Sheffrin, DMA, California Independent System Operator, Dec. 3, 2003. 
S T A T E O F T H E M A R K E T S

27

Southern Co., for example, controlled 66 percent of 

installed generation and 51 percent of peaking capacity in its 

market. The second largest generator in the Southern service 

area27 controlled 7 percent of installed and peaking capacity. 

Similarly, in both the Entergy and TVA28 subregions of 

SERC, ownership of generation was heavily concentrated in 

a single entity, a vertically integrated utility that controlled 

transmission service. The second largest market share was 

less than 10 percent. Detail of the pattern of generation 

ownership in the regions without organized markets is 

provided in Appendix 3. Of the 12 regions examined, eight 

had moderate or high levels of concentration of generation 

ownership. Four (SPP, MAIN, ECAR and AZ-NM-SNV) exhibited low levels of concentration in generation ownership. 

These observations are consistent with the pivotal 

supplier analyses29 filed by jurisdictional entities in these 

regions. During 2003, the Commission issued orders 

in about 285 dockets finding that the applicant had 

passed, or was exempt from, the pivotal supply screen 

and authorizing continuation or new market-based rate 

authority. Approximately 140 dockets are pending before 

the Commission wherein the Commission will determine 

whether the applicant is a pivotal supplier in the market. An 

initial review indicates that many of these will not pass the 

supply margin assessment and, accordingly, will be found to 

be a pivotal supplier. This preliminarily indicates that during 

the assessment period there were regions without organized 

markets where the basic conditions necessary for achieving 

competitive performance were not in place. 

Barriers to Entry

Independent power producers (IPPs) frequently 

objected to the operation of transmission services in regions 

without organized markets. These complaints alleged that 

the incumbent vertically integrated utilities used the administration of transmission services to discriminate against 

independent generators to the advantage of the incumbent’s 

generation affiliates. Several types of discriminatory practices 

were mentioned in complaints, including:

 transmission provider favoring itself or its affiliate using 

available transfer capability (ATC) postings, 

Figure 16: Southern subregion of SERC generation ownership concentrated.

Note: Installed capacity is the measured capacity or the capacity demonstrated to have been available during the hour of highest output of a 

generating unit. For purposes of this analysis, the working definition of a peaking unit is a natural gas or oil-fired unit with a heat rate greater 

than 10,000 Btu/kWh or a combustion turbine or internal combustion unit smaller than 50 MW in size with no reliable heat rate information 

reported. MWh produced is the net generation of an electric generating unit, or the amount of gross generation less the electrical energy 

consumed at the generating station(s) for station service or auxiliaries. Electricity required for pumping at pumped-storage plants is regarded as 

electricity for station service and is deducted from gross generation.

Source: Platts POWERdat, Modeled Production Costs-Ownership-Based dataset for calendar year 2002. Analysis and graphic by OMOI.

27 Southern Co. is the control areas operator for one of the subregions of 

SERC. The other subregions of SERC are Entergy, TVA, VACAR and FRCC. 

OMOI has examined the Florida subregion (FRCC) as a region separate 

from the other SERC subregions. 28 The Tennessee Valley Authority (TVA) is a public power entity. TVA, a wholly owned federal corporation, was established by Congress in 1933 to manage the navigation, flood control, power supply, water quality, recreation 

and land use of the integrated river system in the Tennessee Valley region. 

TVA generates and transmits power to local power distributors, such as 

municipalities, cooperatives, and federal agencies, and to large industries. 29 A pivotal supplier is a power supplier whose capacity must be used to 

meet peak demand and whose capacity exceeds the market’s supply margin. These analyses consider transmission constraints and obligations for 

retail service.
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

28

 discretionary dispatch to create constraints that block a 

competitor’s scheduled power flows, 

 preferential administration of energy balancing provisions to gain advantage over competitors, 

 exploiting the native load preference to tie up transmission capacity and impede power flow schedules of competing generators, 

 abuse of discretion in computing transmission reliability 

margins and capacity benefit margins and unnecessary 

delays on feasibility studies for transmission access.

Given the more limited market price transparency of 

the areas outside regions with organized markets,30 it is 

difficult to assess the potential customer costs associated 

with these behaviors.

In conclusion, the market structures in regions with 

organized markets were relatively competitive during the 

assessment period, providing the basic conditions and 

support for the competitive performance of these markets. 

Load pockets in these regions were important exceptions 

to this general result. The market structures in eight of the 

12 regions with bilateral markets provided significantly less 

support for competitive market performance, with control of 

both generation and transmission service concentrated in a 

single or a few vertically integrated entities. In such regions, 

the basic conditions and market structure for achieving 

competitive performance did not appear to be in place. 

Further analysis is needed and OMOI will continue to refine 

its analytical methods. 

Prices, Market Activity, 

Congestion and Mitigation

Short-term Markets in Regions with 

Organized Markets

We observed that reported electricity prices in regions 

with organized markets31 generally behaved in accordance 

with forces of supply and demand observed over the 

assessment period. It is important to note that market 

designs were not consistent across ISO-NE, NYISO, PJM, 

ERCOT and CAISO, though all five regions operated some 

form of real-time balancing markets. ISO-NE, NYISO 

and PJM also operated day-ahead energy markets. PJM, 

NYISO and ISO-NE operated LMP systems,32 while CAISO 

and ERCOT used zonal systems. Prices, market activity,33

congestion and mitigation during the assessment period are 

discussed broadly across regions below, followed by more 

detailed region-specific discussion.

Figure 17 and Table 6 show prices of representative 

price points for each region.34 As evident from the table and 

figure, prices in organized markets averaged lower than in 

2001. ISO prices in 2002 declined 8–15 percent, with the 

exception of CAISO markets, which declined 77 percent 

from 2001 levels. Milder weather, new generating capacity, 

inexpensive natural gas and improved hydroelectric conditions in the West contributed to the lower 2002 prices. Prices 

began to increase with the rise and spike of natural gas 

prices in late February and early March 2003 and remained 

at moderately higher levels (20–30 percent higher than in 

2001) through mid-2003. Again, CAISO was an exception 

with first-half 2003 prices nearly 70 percent below 2001 

levels. ERCOT was another exception with average first-half 

2003 prices more than double the average 2001 level. All of 

the RTO and ISO markets and most other electricity markets 

in the country experienced the highest prices of the assessment period in February/March 2003 as the natural gas price 

spike was reflected in electricity prices. Comparison of prices 

across regions is difficult due to variations in product definitions and market structures, but the overall trend across 

these markets is evident. 

During the assessment period, prices and trends for 

bilateral transactions as reported by ICE35 and Megawatt 

Daily are similar to those from the ISOs. Differences evident 

in Table 6 are in part due to data availability. For example, 

the average price in CAISO in 2001 as reported by ICE is 

significantly less than ISO and Megawatt Daily prices because 

the selected price point, NP-15, traded intermittently on ICE 

in 2001. Peak ISO prices are often higher than peak ICE 

and Megawatt Daily prices because they reflect real-time 

supply needs and transmission constraints, whereas ICE and 

Megawatt Daily prices reflect day-ahead expectations. 

30 For further discussion, see the section on prices in regions without organized markets. 31 For a map of these regions, see Figure 8. 32 In NYISO and ISO-NE, loads paid zonal prices, which are averages of nodal 

LMPs within the zones. 33 To compare price, volatility and market activity across regions, OMOI 

selected one representative pricing point for each region, based on factors 

such as underlying liquidity and location. A map of price points is located 

in Appendix 6. 34 ISO prices were determined as follows: Real-time hourly prices during the 

peak hours in each region for each were averaged. The peak hours for each 

region are the hour ending 8 am through the hour ending 11 pm in the 

ISO-NE, PJM and NYISO markets and the hour ending 7 am through the 

hour ending 10 pm in CAISO and ERCOT. Peak days are considered to be 

Monday–Friday. CAISO considers Saturdays peak days, but they were left out 

of the chart so that NP-15 prices could be compared with the other regions. 35 During the assessment period, an additional source of bilateral price information emerged through reports from the IntercontinentalExchange (ICE), an 

online broker. ICE was launched in August 2000 as an internet platform for 

bilateral trades of energy, precious metals, weather and emissions. ICE began 

facilitating trading of energy on the platform in October 2000. Power products traded over-the-counter include physical electricity delivery at 18 power 

hubs for time periods ranging from same-day hourly power to full calendar 

years. ICE does not take title or participatory interest in any transaction. 
S T A T E O F T H E M A R K E T S

29

Figure 17: Organized market power prices generally lower and more stable than in 2001.

Note: Megawatt Daily and ICE data are volume-weighted day-ahead peak prices. ISO data are averages of real-time hourly prices during peak hours. 

For more information, see footnote 34. NYPP Zone G (Hudson Valley) did not have an active market for day-ahead power on ICE. A map of price 

points is located in Appendix 6.

Source: Platts Megawatt Daily, ICE, ISO-NE, NYISO, PJM, ERCOT and CAISO.36 Analysis and graphic by OMOI.

36 NP-15 prices are for CAISO incremental (INC) energy in the North of Path 

15 zone as recorded on CAISO’s OASIS. NP-15 data do not include prices 

CAISO paid for out-of-sequence (OOS) and out-of-market (OOM) energy. In 

2001, the market-clearing price was limited by various soft caps, including 

a soft cap of $150/MWh, January through April 2001. Bids were accepted 

above the soft cap and paid as-bid subject to cost justification. In January 

2001, the overall monthly average real-time energy price, including OOM 

and OOS, was $290/MWh. The as-bid and OOM purchases diminished 

substantially over the first half of the year and, by December 2001, the 

overall monthly average real-time INC energy price was $57/MWh. (CAISO 

Department of Market Analysis, Market Analysis Report, Feb. 16, 2001 

through Feb. 1, 2002.)
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

30

Table 6: Electricity prices in regions with organized electricity markets.

 Price ($/MWh) 2001 2002 First half of 2003

First half of 2003

(adjusted***)

Min Max Mean Min Max Mean Min Max Mean Min Max Mean

ISO-NE

ICE 26.17 130.00 47.16 25.13 130.80 43.24 46.00 146.20 65.86 46.00 100.05 61.83

MWD 26.41 411.60 52.26 25.05 141.50 43.40 46.33 149.22 65.40 46.33 120.25 61.28

ISO 21.93 537.92 49.18 23.29 305.06 41.96 43.60 128.34 63.66 43.60 124.55 60.05

NYISO [NYPP 

Zone G 

(Hudson Valley)]

ICE N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A

MWD 27.29 209.00 51.54 25.50 116.53 46.62 45.44 140.00 66.88 45.44 120.00 60.60

ISO 21.40 382.71 48.72 18.57 297.33 44.75 33.27 139.01 63.06 33.27 137.89 60.20

PJM Western Hub

ICE 19.99 288.83 40.46 21.14 116.02 35.86 30.43 118.46 54.17 30.43 108.53 51.10

MWD 20.21 299.60 40.56 21.09 115.57 35.86 30.33 117.79 54.06 30.33 108.99 50.93

ISO 15.84 556.87 43.20 16.44 149.04 37.20 21.97 122.64 52.75 21.97 111.98 49.91

ERCOT

ICE* 17.00 75.00 30.75 15.26 45.55 29.12 36.59 316.25 52.76 36.59 78.00 48.07

MWD 16.59 91.44 39.15 16.57 45.57 29.25 36.50 293.00 52.34 36.50 74.11 48.07

ISO** 3.68 116.60 24.42 10.12 111.23 26.74 26.59 615.13 57.97 26.59 159.91 47.84

CAISO [NP-15 (ICE, 

MW),

INC (ISO)]

ICE* 17.52 435.00 71.46 19.24 63.68 33.47 32.96 115.72 49.83 32.96 67.01 47.01

MWD 17.74 513.75 134.56 19.20 65.17 33.60 32.93 118.62 49.88 32.93 72.79 47.32

ISO 13.78 519.60 157.92 18.47 65.79 36.37 25.50 86.96 51.45 25.50 72.96 49.45

Notes: *Traded intermittently. **Data begin 7/31/2001. ***Excludes 2/24–3/9 (period of February/March 2003 natural gas price spike). Megawatt 

Daily (MWD) and ICE data are volume-weighted day-ahead peak prices. ISO data are averages of real-time hourly prices during peak hours. For 

more information, see footnote 34. 

Source: Platts Megawatt Daily, ICE, ISO-NE, NYISO, PJM, ERCOT and CAISO. See footnote 36 for details on CAISO. 

Figure 18: Organized market volatility declines.

Note: Data are day-ahead on-peak prices. Annualized historical volatility is calculated as the annualized standard deviation of logarithmic returns, 

log (pricet /pricet-1), where standard deviation is based on all on-peak days (weekdays excluding NERC holidays) during the period. 

Source: Platts Megawatt Daily. Analysis and graphic by OMOI.
S T A T E O F T H E M A R K E T S

31

As shown in Figure 18, price volatility generally declined 

since 2001, except for the large increase in ERCOT due 

to a steep price spike in late February 2003 in the region. 

In comparison, the volatility of physical natural gas prices 

increased during the assessment period (see Figure 53), but 

at the 70 percent level, was significantly below the 150–250 

percent levels experienced in organized electricity markets. 

In addition, price volatility in organized markets was lower 

than levels experienced in regions without organized 

markets (see Figure 27). 

Market activity data offer information about liquidity 

and participation. As shown in Table 7, participation in or 

RTO real-time balancing markets and day-ahead markets was 

robust during the assessment period. 

The apparent decline in volumes traded in the CAISO 

market from 2001 to 2002 stems from unusually high 

volumes traded in the first five months of 2001, which 

was during the energy crisis. This high volume of trading 

was conducted by California Energy Resources Scheduling 

(CERS), a state entity that purchased energy in real time to 

meet the net short needs of California’s utilities—primarily 

Pacific Gas & Electric (PG&E) and Southern California 

Edison (SCE)—when they could no longer make the 

purchases or contract on their own due to insolvency.37

Thus the 2002 volumes, which were less than approximately 

5 percent of system load,38 reflect a level of trading more 

consistent with the design of the CAISO’s imbalance market. 

The decline in volumes in the ISO-NE real-time 

market is due to a market-design change. In March 2003, 

a day-ahead market began, making the real-time market a 

residual market. 

The decline in real-time market volumes in NYISO 

between 2001 and 2002 should be viewed in the context 

of the small and variable real-time market share. During 

the 18-month assessment period, monthly real-time market 

shares ranged between negative 1.6 percent and positive 3.6 

percent. This variability reflects the primary function of the 

real-time market: to balance differences between day-ahead 

expectations and actual consumption. Day-ahead forecasts 

of consumption commonly have errors of plus or minus 2 

percent. These are likely to be the major cause of variability 

in real-time volumes. Another factor may have been the small 

decline in consumption between 2002 and 2003, due to 

weather and the economic downturn in the region.

It is also possible that, as the market matured, NYISO 

participants became more comfortable putting most or 

all of their load into the day-ahead market rather than 

the real-time market. Two trends lend support to this: the 

narrowing of wide divergences between hour-ahead advisory 

prices and real-time prices, and the introduction of virtual 

transactions in November 2001 that tended to limit the 

differences between day-ahead and real-time prices (and 

allow hedging). However, it is likely that typical variations in 

real-time volumes due to forecast error are a more important 

explanation of the decline in market activity than increased 

confidence in the day-ahead market.

Table 7: Electricity volumes transacted in organized markets.

000 GWh 

(cumulative) Day-ahead market Real-time market

Region 2001 2002 2003 thru 

6/30/03 2001 2002 2003 thru 6/30/03

ISO-NE (1) (1) 11 (2) 30 41 8 (2)

NYISO 161 162 77 3 1 2

PJM 42 104 60 57 119 67

ERCOT (3) N/A N/A N/A 1 7 5

CAISO (4) N/A N/A N/A 14 2 1

Notes: (1) Day-Ahead Market initiated March 1, 2003. (2) Only includes transactions from March 1 to June 30. In addition, after March 1, 2003 the 

real-time market was only a residual market. (3) ERCOT does not have a day-ahead market. Real-time energy balancing market began July 31, 2001. 

Real-time market data are for real-time Balancing Up energy. (4) CAISO does not have a day-ahead market. Real-time market data are for Incremental 

(INC) energy. 

 Source: ISO websites and ISO MMU response to OMOI data requests. 

37 PG&E and SCE became insolvent during the energy crisis in early 2001, 

while San Diego Gas & Electric did not. 38 CAISO, 2001 Annual Report, p. 17 (www.caiso.com/docs/09003a6080/13/f0/

09003a608013f05b.pdf) 
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

32

Figure 19: Reported bilateral trading volumes in organized markets decline.

Note: ICE did not report trade volumes for day-ahead power for NYPP Zone G (Hudson Valley). Megawatt Daily volumes reflect on-peak transactions 

surveyed by the trade publication. Megawatt Daily data have been modified to make them comparable to ICE data. Megawatt Daily volumes have been 

multiplied by 16 to convert from a 16 peak-hour MW contract into a MWh. Final volumes are converted to GWh. In addition, since Megawatt Daily volumes include both buy and sell sides of transactions and ICE volumes include only the sell side of transactions, ICE volumes were doubled.

Source: Platts Megawatt Daily and ICE. Analysis and graphic by OMOI.

Table 8: Reported bilateral trading volumes in regions with organized markets.

Average daily

volume (GWh)

ISO-NE NYPP ZG PJM ERCOT NP-15

MWD ICE MWD ICE MWD ICE MWD ICE MWD ICE

2001 (full year) 48 12 11 N/A 111 66 34 7 10 7

2002 (full year) 14 26 8 N/A 77 129 34 15 21 31

2003 (first half) 10 11 3 N/A 32 66 12 8 17 29

Note: ICE did not report trade volumes for day-ahead power for NYPP Zone G (Hudson Valley). Megawatt Daily volumes reflect on-peak transactions 

surveyed by the trade publication. Megawatt Daily data have been modified to make them comparable to ICE data. Megawatt Daily volumes have 

been multiplied by 16 to convert from a 16 peak-hour MW contract into a MWh. Final volumes are converted to GWh. In addition, since Megawatt 

Daily volumes include both buy and sell sides of transactions and ICE volumes include only the sell side of transactions, ICE volumes were 

doubled.

Source: Platts Megawatt Daily and ICE. 
S T A T E O F T H E M A R K E T S

33

Data from ICE and Megawatt Daily give some insight 

into bilateral market activity in each region, but contain only 

a subset of short-term bilateral contracts, those conducted 

on ICE or reported to Megawatt Daily. Depending on the 

relative size of a region’s reliance on long-term bilateral 

transactions and short-term ISO or RTO transactions, the 

overall and relative size of a region’s short-term activity may 

not be accurately represented by volumes of short-term 

bilateral transactions. For example, Figure 19 and Table 8 

indicate that activity in New York Power Pool (NYPP) Zone 

G (Hudson Valley) was small compared to other regions. 

However, this is consistent with data from EQR that indicate 

short-term bilateral deals were a relatively small part (19 

percent) of reported transactions in New York generally, 

whereas short-term deals conducted through the ISO 

markets are 52 percent of total reported transactions.39 This 

is in contrast to CAISO, where short-term deals conducted 

through the ISO accounted for a small percentage (1 

percent) of total transactions and short-term bilateral deals 

accounted for a large percentage (76 percent). 

Despite data limitations, it is clear that trading generally 

declined during the assessment period due to the financial 

deterioration of the energy market and decline of creditworthy 

participants. This limited risk management options for market 

participants and could indicate inefficient market pricing. 

Transmission congestion affected electricity prices to 

varying degrees in each region. Congestion can effectively 

prevent a distant but lower-priced generator from providing 

more energy at a particular point, forcing a higher priced 

generator to be used. Locations with chronic congestion, 

load pockets, have insufficient generation capacity within the 

pocket compared to peak demands and the area’s transmission network is limited in its ability to import additional, 

often lower-cost resources from outside the pocket. 

LMP systems, which were used in ISO-NE, NYISO 

and PJM, contain a congestion component that explicitly 

prices the cost of congestion. When there is no transmission 

congestion, the congestion price component is zero and all 

locational prices in the region are equal, except for variation 

that reflects marginal losses.40 When transmission facilities 

are constrained, the marginal price at one location—the 

cost of the next increment of energy supplied there—differs 

from other locations that are more or less affected by the 

constraints, and the congestion price component reflects 

the cost differences. ERCOT and CAISO used zonal systems 

and while zonal systems reflect price differentials due to 

congestion, the differential is most clearly reflected in an 

LMP system. 

Congestion costs during the assessment period varied 

across regions and cannot be directly compared due to 

differences in market design and congestion cost accounting. For example, congestion costs in ISO-NE totaled $139 

million during the assessment period.41 However, from 

January 2002–March 2003, prior to the introduction of 

its LMP system, this figure may have included costs for redispatch not associated with relieving a constraint. NYISO’s 

$793 million in congestion costs during the assessment 

period comprises a significant amount of total energy costs—

19 percent when compared to total invoices.42 These costs 

are due primarily to constraints on five interfaces in or near 

the heavily congested New York City region. Congestion costs 

in PJM were $430 million in 2002, up from $271 million 

in 2001.43 Congestion in PJM is different from congestion 

found in other markets because it tended not to occur on the 

same transmission lines frequently or only during periods 

of high load as in other markets, but rather throughout the 

region and often during off-peak hours. The increase in 

congestion costs in PJM is primarily due to the addition of 

PJM West, which brought in low-cost coal-fired power that 

lowered prices in the western part of PJM but did not affect 

the eastern part due to constraints in the system. California 

reported relatively low congestion costs—$53 million in 

interzonal congestion costs during the assessment period 

and $10 million in intrazonal congestion costs in 2002 

only.44 Since CAISO is a zonal system, congestion costs are 

made explicit between CAISO’s three zones, not at multiple 

locations within zones. As a result, CAISO underestimates 

intrazonal congestion costs. Data on congestion costs for 

ERCOT were not available.

Finally, mitigation procedures and frequency of use 

varied across regions. Mitigation has important effects on 

both short- and long-term prices in electricity markets. 

Market operators use mitigation procedures to prevent the 

exercise of market power. However, if the mitigation is not 

warranted because there is no exercise of market power, the 

mitigation suppresses prices signals, resulting in diminished 

investment in needed infrastructure. That, in turn, results 

in higher prices in the longer term. Price suppression has 

particularly problematic effects in load pockets, areas in 

need of infrastructure investment. Mitigation procedures 

and frequency of use during the assessment period are 

summarized by region in Table 9. More detailed discussion 

of mitigation is included in the regional analyses below.

39 Derived from FERC EQR, Fourth Quarter 2002 through Second Quarter 

2003. For more information on EQR data used in this report see footnote 5. 40 The inclusion of marginal losses can result in significant LMP variation 

across regions. For example, in NYISO, marginal loss factors (i.e., the 

marginal loss component of LMPs expressed as a percentage of the 

energy component of the reference bus LMP) can vary as much as 20 

percent for a power transaction from Western NY to NYC/Long Island. 

Both NYSIO and ISO-NE include marginal losses in their LMP calculation. 

LMPs in PJM do not. 41 ISO-NE response to data request and 2002 Annual Market Report. 42 NYISO response to data request. 43 PJM, 2002 State of the Markets.

44 CAISO, 2002 Annual Report on Market Issues and Performance.
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

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Table 9: Mitigation procedures by region.

Market Type Where it applies Calculation Frequency

*ISO-NE Bid Cap System $1,000 

Local (PUSH) Designated 

Congestion Areas 

(DCAs)

Units are subject to a conduct and impact test. For units with less than a 

10% capacity factor, the reference and the threshold are the sum of the 

unit’s fixed and variable costs. If the unit fails both conduct and impact 

tests and behavior is unexplained, the ISO can substitute a reference 

price for the faulty bid or offer.

No Peaking Unit Safe 

Harbor (PUSH) bids 

have been mitigated

Pivotal 

Supplier** 

System-wide 

during unconstrained hours

Energy bid exceeds reference price by 300% or $100. Other thresholds 

exist for no-load, regulation and other types of offers. If unit fails conduct 

and impact tests and behavior is unexplained, ISO can substitute reference price for faulty bid.

This provision 

became effective 

7/1/2003

Local (RMR) Unit specific Cost of service No RMR bids have 

been mitigated

Other units 

during constrained 

hours

System-wide 

during constrained hours

Energy bids exceed reference price by 50% or $25. This is more stringent 

than pivotal supplier threshold. Other thresholds exist for start-up and 

no-load. If the unit fails both conduct and impact tests and behavior is 

unexplained, the ISO can substitute a reference price for the faulty bid or 

offer. 

4 instances

NYISO Bid Cap System $1,000 

Conduct and 

Impact (AMP)

System-wide Reduced to reference price if (a) bid exceeds reference level by 300% or 

$100 and (b) bid would raise price by 200% or $100 (different thresholds 

apply to reserves and other bid parameters).

No bids mitigated 

between 1/1/2002 and 

6/30/2003

Local (Incity)New York City DA: reduced to reference price when 7% higher than INP#2 bus. RT: 

reduced to reference price when load pocket congested, if bid is 300% or 

$100 above reference level and proxy impact exists.

DA: about 50% of unit 

hours; RT: about 20% 

of unit hours

PJM Bid Cap System $1,000 

Local RMR units in constrained areasPre-determined Variable Cost Plus 10% The average number 

of units mitigated in 

any month did not 

exceed 1%. However, 

some affected units 

had significant hours 

of mitigation.

ERCOT Bid Cap System $1,000 

Competitive 

Solution 

Method

System Evaluates market conditions as a whole. The conditions for a market to 

pass are (a) total bids to provide a service must amount to at least 115% 

of what ERCOT needs, and (b) the market-clearing price must not be set 

by a pivotal bidder.

No bids mitigated 

between 1/1/2002 and 

6/30/2003***

Local Constrained areas Three or more suppliers required for Market Solution. In case of less than 

three suppliers, out-of-merit (OOM) dispatch using generic cost based 

offers that vary by type of unit. 

Market Solution rare 

for constrained areas. 

Approach suspended 

after sudden increase 

in costs in June 2003

CAISO Bid Cap System $250 (soft cap)

Bid Cap DEC Energy - $30 (soft cap)

Conduct and 

Impact

 Real-Time Dispatched in Hour Ahead Market when predicted prices exceed $91.87

Conduct test = bid over 200% of Reference or $100 over Reference

Impact test = bid increases price by lesser of 200% or $50

1582 bids failed 

the Conduct Test 

between 1/1/03–11/

25/03, no Impact Test 

failures, no mitigated 

bids

Local RMR contracts Condition 1 Units: Market Based, Condition 2 Units: Cost Based

Local Constrained Area If bid exceeds the zonal price by lesser of 200% or $50, it is reset to 

higher of zonal price or the unit’s reference price. There is no separate 

impact test.

Notes: Reliability Must Run (RMR) generating units are units identified by the ISO as necessary for operational or reliability reasons and must run, 

regardless of economic considerations. *New England had other types of mitigation mechanisms dealing with physical withholding, uneconomic 

production and reliability must run (RMR) agreements. **A pivotal supplier is any participant whose aggregate energy supply offer is greater than 

the NEPOOL supply margin. The NEPOOL supply margin is the total energy supply offer for each hour less total system load, including net imports 

and operating reserves. ***A bid of $990 was made in late February 2003. 

Source: OMOI.
S T A T E O F T H E M A R K E T S

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Figure 20: ISO-NE prices increase.

Note: Daily load-weighted average energy price.

Source: ISO-NE. Analysis and graphic by OMOI.

Variations in price, market activity, congestion and 

mitigation by region are important. We consider these 

variations over the assessment period in each of these 

markets separately.

ISO-NE

On March 1, 2003, New England replaced its uniformly 

priced, real-time market with day-ahead and real-time markets 

and LMP. Both the former and the current market’s responses 

to variations in demand and input prices are what one would 

expect from a well-functioning market. As shown in Figure 20, 

prices were relatively stable at about $30/MWh in the first half 

of 2002 due to mild weather and stable input prices. 

Successive heat waves in summer 2002 generated a series 

of historic peak demand days and corresponding price spikes. 

In the fall, prices stabilized again but at slightly higher levels, 

around $43/MWh. During the winter months, prices rose to 

a monthly average of well over $60 as natural gas prices rose. 

Over the period, Jan. 1, 2002 through Feb. 28, 2003, there were 

eight instances—all during summer 2002—when prices rose 

above $200.

Since the start of the new market, average day-ahead and 

real-time prices were in the $52/MWh range. For the most 

part, day-ahead LMPs were higher than real-time LMPs and, as 

expected, real-time LMPs were more volatile than day-ahead 

LMPs due to unforeseen intra-day events such as outages, 

deviations between forecast and actual load and changes in 

operating conditions. Since March 1, 2003 LMPs exceeded $200 

in 21 day-ahead hours and 37 real-time hours,45 mainly due to 

a combination of cold temperatures, high gas prices and virtual 

bidding46 in the first half of March 2003—and later due to 

various facilities outages/failures and congestion. 

The most heavily congested areas in New England were 

Southwest Connecticut and the Boston area. The zones that 

include these congested areas exhibited higher congestion cost 

components than zones such as Maine, which was an exportconstrained area (for a map of zones, see Figure 69). Although 

congestion was not significant in Vermont,47 reliability was a 

critical concern, particularly in Northwest Vermont, due to 

increasing loads, weak links with the main transmission system 

and a lack of power plants in the area.48 Both Connecticut 

and Vermont currently have transmission projects in the 

review/siting process designed to alleviate reliability concerns 

and congestion. 

45 Note that the text refers to hourly prices and Figure 20 shows daily average 

prices. In addition, the figure shows hub prices only while the text refers to 

the prices across the load zones (eight zones and one hub) in ISO-NE. 46 Virtual bids are included in the day-ahead supply stack. As a result, they 

can make a node appear more congested in the case of an incremental 

bid (an offer to sell) or less congested in the case of a decremental bid 

(an offer to buy). 47 ISO-NE’s economic dispatch software operates by selecting a reference 

location (not necessarily physical location) where congestion costs and 

losses are assumed to be zero. The price at this reference location is used 

as the system wide energy component of the LMP. Ignoring the effect of 

losses, the congestion component of the LMP for each pricing node (zone) 

is calculated by subtracting the system-wide energy component price from 

the LMP at the node (zone). As a result, nodal (zonal) congestion components can be either positive or negative. The LMP is always the cost to serve 

an additional increment of load. Thus, the selection of a reference location doesn’t change the LMP, although the selection can create somewhat 

counterintuitive negative congestion component of the LMP. A high positive 

congestion LMP component indicates that the lines in that region are more 

heavily congested than in regions with lower congestion components. 

Conversely, lines in areas with negative congestion components tend to be 

more lightly loaded. However, there is not necessarily a linear relationship 

between the LMP and the loading of the line (Source: ISO NEWS, ISO-NE, 

Apr. 18, 2003). 48 ISO-NE, “RTEP03 Executive summary and Overview,” Second Draft of 

the 2003 Regional Transmission Expansion Plan (RTEP03). Sept. 12, 

2003. Only about 15 percent of load in Northwest Vermont is met with 

local generation.
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

36

New England’s hub is a set of pre-defined, relatively 

unconstrained nodes in Massachusetts and the ISO-NE hub 

price is the simple average of the LMPs at the applicable nodes. 

In practice, however, prices at the hub were fairly volatile due 

to imbalances between incremental offers and decremental 

bids. The increased volatility made risk management more 

difficult, reducing liquidity. Possible solutions being considered 

by NEPOOL are reconfiguring or redefining the hub.49

To maintain or improve system reliability in load 

pockets, the ISO has the authority to negotiate Reliability 

Must Run (RMR) agreements. RMR agreements are a mechanism for insuring that high priced units that operate at low 

capacity factors are able to recover their costs and, thus, 

remain in-service and available to the ISO. The difference 

between the amount that is paid to the generator under the 

RMR contract and the energy clearing price is recovered 

from the market participants in the form of uplift.50

On June 1, 2003, New England implemented a temporary mechanism called the Peaking Unit Safe Harbor (PUSH) 

offer rules. The goal of PUSH is to increase opportunities 

for high cost but seldom run units in designated congestion 

areas (DCAs)51 to recover their fixed and variable costs 

through a market mechanism and to produce signals for 

investment through higher LMPs in these areas during 

periods of scarcity. Under PUSH, generators in DCAs with a 

capacity factor52 of 10 percent or less in calendar year 2002 

can submit energy offers up to their marginal energy costs 

plus their levelized fixed costs, without the imposition of 

mitigation measures.53

Recently, ISO-NE issued a report on PUSH’s performance that covers a portion of the assessment period.54 The 

report finds that PUSH enabled greater cost recovery than 

could have occurred under the previous mitigation rules, 

but that it is unlikely that the PUSH units will be able to 

recover all of their fixed costs. One of the reasons for this 

expectation is that the PUSH unit’s levelized fixed costs are 

determined using 2002 data and the unit’s output in 2002. 

Because of overall milder temperatures and hence lighter 

loads, the PUSH unit’s capacity factors in 2003 were less than 

in 2002. The average capacity factor for units receiving PUSH 

treatment during the summer of 2003 was approximately 

35 percent of the capacity factor of those same units during 

the summer of 2002. The report also finds that the PUSH 

units were primarily dispatched out of merit order solely to 

provide reserves, not as a part of the system-wide dispatch. 

The result is that the PUSH units seldom set the electric 

clearing price, the anticipated price signal for investment. 

The ISO is required to replace PUSH with a locational 

installed capacity (ICAP) requirement, deliverability requirements or similar modifications to the existing ISO-NE 

capacity market no later than June 1, 2004. 

The ISO’s market monitoring group is charged with 

evaluating economic withholding in the New England electricity market. From Jan. 1, 2002, until March 1, 2003, the 

Market Monitoring Group (MMG) performed this evaluation 

under Market Rule 17.55 From March 1 forward, the MMG 

performed this evaluation under Appendix A of Market Rule 

1. The rules are similar; the MMG imposes mitigation if:

 a participant exceeds a specified conduct threshold relative to an established conduct history, 

Table 10: Congestion cost components in ISO-NE zones.

Hub and load zone name Average real-time congestion component

(March –June 2003)

Connecticut $0.34/MWh

Northeastern Massachusetts (including Boston) $0.16/MWh

Southeastern Massachusetts $0.07/MWh

Rhode Island $0.06/MWh

Western/Central Massachusetts $0.05/MWh

ISO-NE Hub $0.04/MWh

Vermont - $0.08/MWh

New Hampshire - $0.40/MWh

Maine - $1.20/MWh

Source: ISO-NE

49 NEPOOL, Hub White Paper, Hub Analysis Working Group, Participants committee, Agenda Item #4, Oct. 29, 2003. 50 Uplift generally refers to costs allocated to all market participants in a given 

region or market and not charged directly to the participant that caused 

the cost to be incurred. Some categories of charges that may be allocated 

to uplift are ancillary services and out-of-merit dispatch costs. 51 DCAs in New England are Northeastern Massachusetts/Boston, Connecticut 

and Southwest Connecticut. These areas are characterized by the frequent 

need to operate generating units out of merit order to satisfy reliability 

needs, and by a chronic need for additional infrastructure. 52 Capacity factor is defined as the percentage of actual unit output over the 

specified time period relative to total possible output over the time period. 53 Non-PUSH and RMR units may bid up to their marginal cost of fuel and 

operating expenses. 54 ISO-NE, Review of PUSH Implementation Rules, Docket No. ER03-563-002, 

filed with the Commission on Dec. 4, 2003. 55 The use of conduct and market impact tests did not apply to physical withholding and mitigation of ICAP resources in Market Rule 17.
S T A T E O F T H E M A R K E T S

37

56 The first level of mitigation occurs when there are no transmission 

constraints.

 that conduct results in a significant price effect as modeled using appropriate tools, and 

 the conduct is unexplained. 

However, the criteria for evaluation and mitigation differ 

under each set of rules. Additionally, each rule contains 

specific general or first level mitigation procedures56 and 

mitigation procedures applicable to congested areas. The 

current Appendix A mitigation procedures are summarized 

in Table 9. 

Under Market Rule 17, the ISO did not implement 

general mitigation during the Jan. 1, 2002 to March 1, 2003, 

period. However, mitigation was imposed frequently in transmission constrained areas. Almost every day a unit or units 

were mitigated under the complicated mitigation formulas 

in Market Rule 17. Appendix A of Market Rule 1 provided no 

authority for general market power mitigation through June 

30, 2003, though this authority was granted in July 2003. 

Congestion mitigation was imposed four times under the 

new market rules between March 1, 2003 and June 30, 2003. 

Due to bidding that exceeded thresholds, mitigation was 

imposed three times during operating reserve evaluation and 

once during real-time market operations. In each case, the 

participants changed their behavior after the mitigation event 

to avoid future risk of mitigation.

The MMG also has responsibility to investigate physical 

withholding under both market rules. Although many units 

were investigated for physical withholding under Market Rule 

17, which required submission of plant operator logs, the 

MMG determined that no physical withholding had occurred. 

Physical withholding was investigated under Market Rule 1 

on days between March 1 and June 30, 2003. MMG personnel physically inspected a generating facility in late-June 

as part of an investigation of physical withholding. In no 

instance did the MMG determine that physical withholding 

had occurred. 

NYISO

The average 2002 NYISO price (including ancillary 

services) was $49.77/MWh, down from $51.39 the previous 

year. The average 2003 price through June was $67.43, 

compared to $39.06 for the same period in 2002 and $55.95 

in 2001. These prices reflected changes in the price of 

natural gas, which was often the marginal fuel in New York. 

Day-ahead prices in Zone G (Hudson Valley) never exceeded 

$200 from July 2002 through June 2003, in marked contrast 

to the previous 12 months when day-ahead prices exceeded 

$1,000 (due to hot weather on Aug. 9 and 10, 2001, when 

New York set all-time load records.) Average monthly prices 

are shown in Figure 21.

Figure 21: NYISO average monthly prices increase.

Note: Does not include ICAP costs.

Source: NYISO. Analysis and graphic by OMOI.
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

38

NYISO day-ahead prices were most volatile in July 

through September 2002, when volatility ranged between 

about 300 percent and 500 percent. In the two six-month 

periods ending June 30, 2002 and June 30, 2003, volatility 

levels were similar, about 100 percent to 300 percent. Realtime prices continued to be more volatile than day-ahead 

because they reflect events that occur after the day-ahead 

market has closed. In the bilateral market, prices for Zone J 

(New York City) during summer 2003 were less volatile than 

in the previous summer. Spring 2003 bilateral prices were 

more volatile than the previous spring, probably as a result 

of volatile natural gas prices. NYISO day-ahead prices and 

their historical volatility are shown in Figure 22.

Prices in NYISO-operated energy markets responded 

as expected to weather-driven load and to fuel prices. One 

exception occurred during an April 2002 heat wave that 

increased load at a time when some generation was out for 

seasonal maintenance. NYISO’s forecasting software issued 

an inaccurate load forecast on two days, contributing to 

a brief spike in real-time prices (not displayed in the dayahead prices in Figure 22). Differences between NYISO’s 

advisory hour-ahead prices and real-time prices (a significant problem in the past) were markedly reduced during 

the assessment period. 

Like ISO-NE, NYISO’s locational prices contain an 

explicit congestion component. NYISO estimates that 

constraints at five transmission facilities had the largest 

congestion effects on prices57 in its market; four of those 

are within or lead to the New York City metropolitan area. 

These facilities were constrained between 16 and 59 percent 

of the time during the assessment period. Transmission 

constraints were thus limiting competition in the city by 

limiting customer access to multiple sellers, necessitating the 

use of more expensive local in-city generation, and raising 

prices. NYISO calculates that congestion58 during the period 

added $793 million to the price of energy in the state. Based 

on NYISO invoices of about $4.25 billion59 during the same 

period, congestion amounted to 19 percent of the costs 

borne by NYISO customers statewide.

NYISO’s tariff defines conduct which may be mitigated 

or penalized, types of mitigation that may be imposed and 

thresholds for imposing them.60 NYISO devised and implemented an automated bid review and mitigation process 

(AMP) with two potential advantages. First, AMP allows 

prices to reflect mitigation as the prices are computed, rather 

than after-the-fact as was previously the case. Second, AMP 

applies mitigation in a way designed to avoid mitigating high 

prices due to genuine scarcity. The process is described in 

Figure 22: NYISO day-ahead volatility peaks in summer 2002.

Note: Data are from average on-peak prices. Historical volatility is calculated as the standard deviation of logarithmic returns, log (pricet /pricet-1), 

where standard deviation is based on the previous 21 on-peak days (weekdays excluding NERC holidays).

Source: NYISO. Analysis and graphic by OMOI.

57 Exact congestion costs for each facility or for the group of five facilities 

were not available. 58 Losses are not included in this amount. 59 NYISO July 2003 Monthly Report, p. 11-C. 60 NYISO Tariff, Original Volume No. 2, Attachment H (eff. July 3, 2001).
S T A T E O F T H E M A R K E T S

39

more detail in Table 9. No bids were mitigated with the AMP 

process during the period of this report.61

Unlike the rest of the state, New York City experiences 

mitigation routinely. Because of concentration in the New 

York City generation market, NYISO manages a separate 

set of mitigation rules there. In the day-ahead market, 

generation bids were mitigated about half of the time62 to a 

fuel-adjusted reference price; the process is similar to mitigation in place before NYISO operations began. 

Within New York City are several sub-areas where 

operating constraints create congestion, raising concerns 

about market power for generators within them. In mid2002 NYISO’s real-time software began modeling nine such 

load pockets. Under the New York City-specific mitigation 

procedures, when congestion (as measured by price differences across the load pocket interfaces) reaches pre-set 

levels, the MMU reviews generator bids to determine if they 

exceed reference levels. If so, and if certain other conditions 

relating to the unit’s effect are met, the MMU mitigates the 

generator’s bids to the reference level.63 Prices were mitigated 

this way about 20 percent of the time in the real-time market 

in New York City.

Mitigation can distort market outcomes, thus NYISO 

has taken measures to offset some of the price suppressing 

effects of mitigation in New York City. For example, the load 

pocket modeling described above has the effect of raising 

prices for some generators in New York City. Before the 

modeling began, the cost of running generators to serve 

load pockets was not included in locational prices but was 

charged as uplift instead. Excluding these costs from the 

locational price tended to suppress prices in New York City 

because needed generators were often costly. Now such 

costs (about $75 million in 200264) are explicitly reflected 

in locational prices, so they send a more accurate signal to 

potential entrants.65 Recent design changes to allow prices 

to better reflect scarcity are intended to improve price 

signals.66 As another incentive to build new capacity, NYISO’s 

mitigation plan sets a more generous reference price for 

new generators in the state during their first three years of 

operation. Their reference price is the 12-month average 

peak price in their zone, if higher than the result of the 

reference price formula.67

PJM

As a general matter, PJM prices responded to load, 

capacity and fuel input prices as expected. A combination of 

adequate supply system-wide, lower fuel prices and a lower 

level of economic activity kept price levels in 2002 generally 

lower than in 2001. As in the rest of the Northeast, an unseasonably warm winter and moderate natural gas costs kept 

average prices during the assessment period through March 

2002 generally below $31/MWh. An April 2002 heat wave 

caused unusually high loads at a time when some generation 

was unavailable because of seasonal maintenance, causing 

brief price increases. Hot weather in July and August 2002 

again drove prices briefly to high levels. Late in the winter of 

2002/03, high fuel prices contributed, along with high loads 

because of the weather, to high electricity prices. However, 

PJM was not affected as severely as other regions by high gas 

prices and gas shortage because it is less reliant on gas-fired 

generation, has better pipeline options and is closer to gas 

storage areas. The prices for PJM’s day-ahead market track 

very closely with comparable prices for similar products in 

the bilateral market, such as peak period, day-ahead energy 

delivered to the Western Hub.

As expected in a well-functioning market, summer 

prices in PJM were sensitive to load, particularly during the 

summer months, as shown in Figure 23. During the assessment period, these price increases at the time of the highest 

loads were of short duration and were more moderate than 

in prior years due to lower fuel prices, capacity additions and 

the addition of Allegheny Power System generation in the 

PJM dispatch. During the first six months of 2003, however, 

fuel price increases worked to reverse that trend. 

Figure 24 shows that day-ahead price volatility was 

consistently lower than the real-time volatility during the 

same period. The relationship between real-time and 

day-ahead volatility is expected and reasonable because realtime prices follow the variations in actual load and supply, 

particularly outages, more closely. Alternatively, day-ahead 

markets tend to rely on typical rather than unexpected 

extreme events in making bids and offers.

61 AMP activates when day-ahead LMPs exceed $150, which occurred on 19 

days in 2003 through June; and on several days (NYISO did not report 

exact numbers) during July, August and September 2002. AMP’s infrequent activation, broad tolerance ranges and lack of actual mitigation 

suggest that it had little effect on prices. 62 Specifically, about one-half of the unit-hours (one generator’s bid during one hour) are mitigated. Preliminary NYISO sampling of day-ahead 

prices suggests that New York City mitigation suppresses prices by 

amounts ranging from $1/MWh to $8/MWh. Source: Staff discussions 

with NYISO. 63 NYISO Technical Bulletin #95 (Dec. 17, 2002). 64 Potomac Economics Ltd., 2002 NYISO State of the Markets Report 

(June 2003). 65 By including congestion in locational prices, load pocket modeling also 

allows congestion costs to be hedged with transmission congestion 

contracts, which was not possible previously. 66 Order Conditionally Accepting Proposed Tariff Revisions (to implement scarcity pricing during reserve shortages); 103 FERC ¶ 61,339 

(June 20, 2003). 67 NYISO Tariff, Original Volume No. 2, Attachment H, Sec. 3.1.4 (c) (eff. 

July 8, 2003).
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

40

In 2002, real-time prices exceeded $400/MWh in three 

hours during the year and there were some persistent load 

pockets that caused localized LMP prices to rise under 

certain load conditions. In general, congestion, in the form of 

higher-than-system LMPs, was observed in high-load periods 

on various paths moving from western supply areas to 

eastern load centers. Forty percent of the congestion in 2002 

occurred in July and August as did 34 percent in 2001.68 The 

primary locations congested under certain load conditions 

during the assessment period include the Delmarva 

Peninsula (the eastern shore of Delaware, Maryland and 

Virginia), Erie (in northwest Pennsylvania), northern New 

Jersey, Bedington-Black Oak (on the Maryland-West Virginia 

border), Wylie Ridge (on the Pennsylvania-Ohio border), 

Doubs (on the Maryland-Virginia border) and TowandaMeshoppen (in northeast Pennsylvania). Some of these 

areas have been the object of transformer upgrades and 

other substation enhancements, which have reduced the 

congestion in certain localities.

Transmission loading relief (TLR), which allows PJM to 

physically curtail load when necessary for the reliability and 

operation of the grid, is an additional, albeit cruder, congestion management tool. PJM still uses TLRs when necessary 

Figure 23: Summer PJM prices sensitive to peak load.

Source: PJM. Analysis and graphic by OMOI.

Figure 24: PJM real-time prices highly volatile.

Note: Data are from average on-peak prices. Historical volatility is calculated as the standard deviation of logarithmic returns, log (pricet /pricet-1), 

where standard deviation is based on the previous 21 on-peak days (weekdays excluding NERC holidays). 

Source: PJM. Analysis and graphic by OMOI.

68 PJM State of the Markets Report, p. 105.
S T A T E O F T H E M A R K E T S

41

to relieve problematic congestion points. TLRs in PJM are 

normally called due to the effects of external loop flow on 

particular paths. This is a problem stemming from running 

an LMP system in PJM adjacent to control areas that do 

not use LMP and are not well coordinated with PJM’s LMP. 

During the assessment period, TLRs in PJM were only used 

to curtail non-firm transmission transactions.

PJM applies its market power mitigation process in cases 

where a generator in a congested load pocket is needed for 

reliability purposes. This mitigation can be applied only to 

generating units whose construction began prior to July 9, 

1996. The affected unit’s supply offers are capped at their 

variable cost plus 10 percent. 

ERCOT

The ERCOT market is based on bilateral transactions 

between buyers and sellers of energy. Balanced energy 

schedules are submitted to ERCOT by qualified scheduling 

entities. ERCOT only operates the electricity market needed 

to resolve the energy imbalances that result due to differences between real-time system requirements and the system 

loading anticipated in the balanced schedules. 

As shown in Figure 17, balancing energy prices69 in 

ERCOT ranged from $15 to $30/MWh through 2002. Prices 

began to rise in 2003 and reached a high of $990/MWh for 

seven hours in late February 2003,70 roughly 80 times the 

average price for the previous week. The peak average daily 

price was $660 during this time period. ERCOT market 

prices are capped at $1,000/MWh. ERCOT’s price spike coincided exactly with the late February 2003 natural gas price 

spike. However, Texas Public Utility Commission (PUCT) 

staff found that hockey-stick bidding71 also contributed materially to the $990 price spikes in the Balancing Up Energy 

Service market during that time period.72 From mid-March 

onward, prices averaged higher than the previous year, 

ranging from roughly $40 to $50/MWh.

Energy prices in the region generally responded as 

expected to variations in demand. Due to the high percentage of power generation capacity fueled by natural gas, the 

price of natural gas was a significant contributing factor to 

electric spot price levels and volatility in ERCOT. In addition, 

increased electric demand for space cooling due to hot 

weather and supply shortages from power generation plant 

outages drove prices higher. These market factors appeared 

to drive price variations during 2002 and 2003. 

For congestion, ERCOT uses a zonal model that classifies the region into four zones (South-North, South-Houston, 

West-North and North-West; see Figure 76), and five 

significant constraint interfaces. In addition, there are local 

constraints that limit the flow of electricity within zones. 

ERCOT solves zonal and local congestion in two steps. In the 

first step, ERCOT dispatches zonal balancing energy to clear 

congestion, sets a price for each constrained interface and 

determines the market-clearing price for each congestion 

zone. In the second step, qualified generators submit bids 

for ancillary service shortfalls required for energy imbalances. If a Market Solution73 can be calculated, ERCOT uses 

these resource-specific premiums to clear local constraints 

and to issue resource-specific instructions to relieve local 

congestion. It uses additional resource-specific procedures 

to rebalance zonal energy. When a Market Solution cannot 

be calculated—the case for more than 90 percent of the 

time that Market Solutions were needed in 2001 and 2002—

ERCOT issues out-of-merit (OOM) dispatch instructions. 

ERCOT-run markets in 2002 used a $1,000 limit on 

offer prices in the energy market. This limit was voluntarily 

followed by market participants for their offers for operating 

reserves as well.

CAISO

Although electricity consumption in 2002 was up 1.2 

percent from the previous year, CAISO energy prices were 

lower in 2002 relative to 2001—particularly lower than in the 

first half of 2001, the end of high prices during the California 

energy crisis (see Figure 17). Overall, California experienced 

improvements to its supply resources because 6,800 MW 

of new generating capacity were added from Jan. 1, 2002 

through June 30, 2003. Hydroelectric supplies also improved 

over the low water conditions in 2001, both in California 

and the Pacific Northwest. CAISO real-time prices continued 

to be volatile in general, but less volatile than in 2000 and 

2001, as participants sold in the real-time market for time 

increments as brief as 10 minutes. 

During the period of this report, in contrast to CAISO’s 

first three years of operation, the vast majority of electricity 

bought and sold in the wholesale market in California was 

69 Balancing energy represents the change in zonal energy output or demand 

determined by ERCOT to be needed to ensure secure operation of the 

ERCOT transmission grid, and supplied by the ERCOT through deployment 

of bid resources to meet load variations not covered by regulation service. 70 Note that Figure 17 and Table 6 are based on the average price during peak 

hours (7 a.m.–10 p.m.) on each day. The $990/MWh price does not appear 

because it is averaged in with the prices from all other peak hours during 

that day. 71 Hockey-stick bidding is when a market participant submits a small portion 

of its bid at an extremely high price. If ERCOT procures all available bids, 

including the tip of the “hockey stick,” then the most expensive megawatt 

hour sets the market-clearing price. 72 PUCT, “Analysis of Balancing Energy Price Spikes During the Extreme 

Weather Event of February 24-26,” filed in Project No. 23100, Market 

Oversight Activities, on March 3, 2003. 73 A Market Solution exists when at least three unaffiliated resources, with 

capacity available, submit bids to ERCOT that can solve a circumstance of 

local congestion and no one bidder is essential to solving the congestion.
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

42

provided through long-term contracts negotiated by the state 

during the energy crisis in 2001.74 The CAISO manages a 

real-time imbalance energy market that reconciles deviations 

between constantly changing system load and generation 

output.75 Figure 25 shows the relationship between longterm contracts and other energy sources. CAISO’s INC and 

DEC energy markets76 manage deviations for real-time only. 

During the assessment period, there was no organized dayahead energy market, resulting in less information about 

actual costs of electric energy in CAISO than provided by 

other RTOs and ISOs about their areas.

INC and DEC energy prices did not always result in 

increasing prices with increasing system load. In some high 

load hours, prices were less than or equal to prices seen at 

lower load levels. Because CAISO’s real-time INC and DEC 

energy markets are largely markets of residuals (CAISO’s 

energy markets fill the relatively small and volatile residual 

needs of the three major IOUs after their own generation, 

long-term contracts and other bilateral purchases), real-time 

energy prices were closely related to the imbalance load 

of the three major IOUs. Other factors such as natural gas 

prices also explained variations in real-time prices. During 

2002, through October, a bid cap provided mitigation that 

limited seller bids. The market-clearing price was thus 

Figure 25: California’s real-time energy market is a small part of total market.

Note: Estimated values of monthly peak generation from CAISO’s real-time energy market, CERS-procured supplies, utility generation, QFs, and 

municipal and Direct Access sources. Estimates are non-coincident. “CERS” is the California Energy Resources Scheduling division of the California 

Department of Water Resources.

Sources: CAISO Oasis, CAISO DMA Annual 2002 Report on Market Issues and Performance, and CAISO DMA data responses. 

Analysis and graphic by OMOI.

74 CAISO and the California Power Exchange (PX) commenced operation in 

April 1998. During the first three years of operation, California’s investorowned utilities were required by state regulations to purchase and sell all of 

their electricity through the California PX with little or no ability to purchase 

through forward contracts. In January 2001, the PX ceased operations. As a 

result of the financial insolvency of PG&E and SCE during the energy crisis, 

the State of California commenced procuring all energy and ancillary services 

for the net short needs of the investor-owned utilities in 2001. By the start 

of 2002, overall utility energy demand was met by a mix of electricity from 

utility-owned generation, existing contracts with QFs, the state-negotiated 

bilateral purchases and long-term contracts and purchases from CAISO for 

balancing energy and ancillary services. In January 2003, the investor-owned 

utilities resumed making purchases from CAISO and bilateral markets to fill 

the difference between their retail customer load and the above described 

resources. Incremental (INC) procurement needs were relatively small, arising primarily from customer load growth. Notably, INC prices during the 

period of this report were based on power purchases for a small amount of 

customer load, less than 5 percent of total load on average, as the CAISO 

market was intended to support. This is in contrast to the large energy volumes in the CAISO market during the electricity crisis. 75 CAISO also operates markets for ancillary services in both the day-ahead 

and hour-ahead. These services include Spinning Reserves, Non-Spinning 

Reserves, Replacement Reserves and Automatic Generation Control/

Regulation capabilities. 76 A separate market clearing price is set for each of six ten-minute intervals in 

an hour for increasing generation output, an INC price, and for decreasing 

generation output, a decremental (DEC) price. The INC and DEC prices 

are determined for three defined zones: NP-15 (northern California), SP-15 

(southern California) and ZP-26 (Central Coast). A single market clearing 

price is set unless there is real-time congestion between the zones.
S T A T E O F T H E M A R K E T S

43

limited to the cap of $108/MWh for the January–April period 

and the cap of $91.87 for the May–October period.77

Congestion cost information was not as clearly revealed 

in the CAISO market framework and prices as in other 

organized markets. During the assessment period, costs 

were split between interzonal and intrazonal congestion. 

Interzonal congestion costs were reflected in the energy 

prices through a usage charge applied to transactions across 

the zonal boundaries and interties. The total interzonal 

congestion costs were $42 million in 2002 and $11 million in 

the first half of 2003. Intrazonal congestion management was 

performed in the real-time market and costs were allocated 

to all scheduling coordinators as an uplift charge in proportion to their scheduled load within a zone (plus net exports 

out of a zone). Total intrazonal variable congestion costs in 

2002 were $10 million. 

The lack of explicit pricing of intrazonal congestion led 

to perverse signals for new generating units. For example, 

three Mexico generating units that came on line July 2003 

were major contributors to intrazonal congestion costs, 

totaling approximately $5 million from July through the 

beginning of October 2003 (annual projected cost is greater 

than $30 million). These generating units operate under 

bilateral contracts. The generating unit suppliers did not 

directly face the costs of the congestion they created under 

the existing CAISO market design. Suppliers may submit 

schedules within a zone without regard to available transmission capacity (e.g., without taking into account transmission 

line or transformer limits within the zone). The costs of 

relieving the congestion from these “infeasible” schedules 

manifest as payments to dispatch generating units out of 

merit order sequence (certain RMR unit dispatch costs are 

included in intrazonal congestion costs). These costs are 

not paid by those who create the congestion, but rather by 

the scheduling coordinators of load within the zone. Such 

intrazonal charges to load are independent of the entities 

that create the congestion and thus provide little incentive 

for suppliers market participants to submit schedules that 

minimize congestion costs.78

While the new generation in Mexico was welcome for 

providing new power supplies, transmission upgrades did 

not keep pace with the new generation. As described above, 

the existing market design flaw of accepting infeasible schedules in the day-ahead period resulted in the ISO needing 

to decrementally dispatch generating units in real-time to 

maintain local grid reliability. CAISO has referred to this case 

as the “DEC game.” The market participants, while creating 

the intrazonal congestion in their day-ahead schedules, are 

not charged for the congestion and then subsequently get 

paid to relieve the congestion by decrementing their flows 

in real time.79 CAISO’s proposed market redesign charges 

congestion costs to those who cause the congestion, which 

should resolve the problem.80

Market power mitigation measures in CAISO consist of 

AMP, a must-offer requirement, a $250/MWh bid cap and RMR 

contracts (see Table 9). While 6,800 MW of new generation 

were added to California, little new generation has been built 

inside the high-load urban areas of San Francisco, Los Angeles 

and San Diego. Because of transmission constraints leading 

into these areas, they continued to have highly concentrated 

generation supply relative to demand and remain load pockets. 

The existing supply within the load pockets would have had 

locational market power in many hours and the CAISO market 

used RMR contracts to mitigate the suppliers’ market power. 

Little progress was made toward investment in load pockets 

that would minimize the need for RMR unit designations. The 

last sizable amount of infrastructure investment made in the 

load pockets, which reduced the quantity of RMR unit designations, was completed in 2000.81 Incentives for new investment 

in load pockets may be weak. While the RMR contracts 

mitigate market power concerns, they, together with CAISO’s 

zonal pricing system (rather than a location-specific system), 

further masked market signals for investment in load pockets. 

Investment signals in load pockets are further removed 

from a locational market-based approach by switching terms 

on the RMR contracts as is an existing option for RMR owners. 

Weak financial conditions of some market suppliers during the 

study period made it attractive to switch RMR contract terms 

to substitute the complete collection of cost-based revenues for 

what they previously opted for: receiving market revenues at 

certain times while receiving a portion of their costs through 

a cost-based formula.82 The alternate contract terms, titled 

“Condition 2,” essentially provide that the RMR unit owner 

77 95 FERC ¶ 61,115 (Apr. 26, 2001 order) and 95 FERC ¶ 61,418 (order on 

rehearing, June 19, 2001). 78 Order on Proposed Tariff Amendment No. 50, 103 FERC ¶ 61, 265. 79 For example, see the California ISO White Paper, “Options for Managing 

Intra-Zonal Congestion on the Miguel Substation” (www.caiso.com/docs/

2003/10/17/2003101716353222638.pdf). 80 The overhaul of California’s electricity markets was initiated by the CAISO 

in December 2001, as a result of the Commission’s Jan. 7, 2000 and Dec. 

19, 2001 orders which required the CAISO to submit a plan for redesigning 

the CAISO congestion management system, and for creating a day-ahead 

energy market (California Independent System Operator Corp., 90 FERC 

P 61,006 at 61,013-61,014 (2000), San Diego Gas & Electric Co. v. Sellers 

of Energy and Ancillary Services Into Markets Operated by the California 

Independent System Operator and the California Power Exchange. et al., 

97 FERC P 61,275 (2001)). 81 Proposals for new generation and transmission have been made in 

California possibly affecting the future quantity of capacity designated 

as RMR depending on whether the projects are approved and financed. 

Source: CAISO-DMA. 82 RMR generating unit owners were able to switch RMR generating units 

providing service under one form of the RMR contract, termed “Condition 

1,” a form that allows the generator to bid into the market and retain market revenues (with certain restrictions) along with a negotiated fraction of 

their annual costs, to another contract form, termed “Condition 2,” a form 

that precludes the generator from retaining market revenues and only a 

cost-based, formula-determined amount of revenues. The switch between 

condition terms is allowed only once per year.
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

44

Figure 26: Regions without organized markets have prices generally lower than in 2001, though spikes occur.

Notes: Megawatt Daily and ICE data are volume-weighted day-ahead peak prices. SPP North and Florida contracts did not have active markets for 

day-ahead power on ICE. 

Source: Platts Megawatt Daily and ICE. Analysis and graphic by OMOI.
S T A T E O F T H E M A R K E T S

45

will receive enough revenue to maintain the unit in operation without the risk of market revenue uncertainty. Though 

revenues RMR unit owners receive are limited to levels that 

were once seen as unattractive (i.e., during the first few years 

of ISO operation), the increased capacity under the cost-based 

Condition 2 form of the RMR contract tended to lower the 

volumes offered in the real-time energy and ancillary services 

markets. This reduction in offers was offset for the overall 

market by new generation that has come on line. OMOI will 

continue to monitor this issue.

Short-term Markets in 

Regions without Organized Markets

Reported electricity prices in regions without organized markets operated by RTOs and ISOs—the Southeast, 

Florida, the Midwest, South Central,83 the Southwest and 

the Northwest84—appear to have generally behaved in 

accordance with observed forces of supply and demand 

over the assessment period, though it is more difficult to 

be certain of this observation due to the limited amount of 

available data. The only source of energy pricing information 

in these regions was indices for electricity to be delivered 

during the 16 peak hours of the next day. Prices for blocks 

of power for the remaining off-peak hours were sometimes 

also available. These price indices did not provide market 

participants with prices for individual hours during the 

coming day. In addition, these prices were derived from a 

subset of transactions, those conducted on ICE and reported 

to trade publications. Organized markets have bilateral price 

and volume transparency, but they also have information on 

price and volume for hourly power derived from the trading 

of all market participants in ISOs or RTOs.

Prices, market activity and congestion during the assessment periods are discussed broadly across regions below, 

followed by more detailed region-specific discussion. 

As shown in Figure 26 and Table 11,85 2002 day-ahead 

bilateral prices in regions without organized markets 

averaged lower than 2001 levels, trending upward in 

summer 2002 and during the February/March 2003 natural 

gas price spike. The average first-half 2003 prices were about 

20 percent higher than full-year 2001 levels, with the exception of the western trading hubs of Mid-Columbia and Palo 

Verde where prices remained significantly below 2001 levels 

through the end of the second half of 2003.

Differences between ICE and Megawatt Daily prices 

evident in Table 11 are in part due to data availability. For 

example, ICE’s mean Palo Verde price is significantly lower 

than the mean Megawatt Daily price because ICE data were 

only intermittently available in 2001.

Table 11: Prices in regions without organized electricity markets.

 Price ($/MWh) 2001 2002 First half of 2003

First half of 2003

(adjusted***)

Min Max Mean Min Max Mean Min Max Mean Min Max Mean

Southeast 

(Entergy)

ICE 16.00 93.00 37.05 16.51 42.48 28.52 22.56 161.63 44.47 22.56 62.27 41.56

MWD 16.40 95.95 37.40 16.64 42.37 28.54 23.25 158.00 44.43 23.25 63.50 41.48

Florida ICE** N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 

MWD* 25.00 97.50 46.19 23.00 71.00 40.29 35.00 135.00 54.37 35.00 92.00 52.53

Midwest (Cinergy) ICE 15.47 156.33 34.98 13.06 60.16 27.01 14.26 128.85 41.86 14.26 81.05 38.70

MWD 15.19 152.97 34.91 14.02 60.94 27.08 14.46 128.51 41.79 14.46 92.02 38.61

South Central 

(SPP North)

ICE** N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 

MWD 16.33 125.00 36.98 17.77 50.00 27.67 17.75 190.00 44.14 17.75 90.00 40.43

Southwest (Palo 

Verde)

ICE* 15.66 537.50 81.38 19.00 69.89 33.02 35.65 119.56 49.92 35.65 73.51 47.41

MWD 15.75 539.03 123.33 18.81 69.39 33.08 35.63 117.94 50.06 35.63 74.30 47.74

Northwest (MidColumbia)

ICE* 13.65 450.00 50.90 1.01 45.70 24.04 15.97 112.71 40.37 15.97 59.06 37.18

MWD 13.63 557.14 145.10 1.43 46.21 24.28 15.56 115.18 37.39 15.56 68.43 37.39

Notes: *Data intermittent in 2001. **Did not have an active market for day-ahead power on ICE. 

***Excludes 2/24–3/9 (period of 2002 natural gas price spike).

Source: Platts Megawatt Daily and ICE. 

83 During the assessment period, Entergy was in preliminary stages to join 

SeTrans, a proposed RTO in the Southeast. For this reason, it was placed in 

the Southeast, not South Central. Depending on future activities, we may 

realign the regions in subsequent reports. 84 For a map of these regions, see Figure 8. 85 To compare price, volatility and market activity across regions, OMOI 

selected one representative pricing point for each region, based on factors 

such as underlying liquidity and location.
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

46

As shown in Figure 27, price volatility in each region 

did not exhibit a unified trend since 2001. Volatility in 

the Midwest (Cinergy), Southeast (Entergy) and South 

Central (SPP North) increased since 2001, whereas volatility 

decreased in the Northwest (Mid-Columbia) and Southwest 

(Palo Verde) during the same time period. The decline in 

volatility in the western regions was due, in part, to more 

stable overall price levels in comparison to the energy crisis. 

Lower levels in the Northwest in particular were due to 

improved hydroelectric conditions.

Both the number of next-day physical transactions 

reported to the index publishers and transacted on ICE 

declined during the assessment period as shown in Figure 28 

and Table 12. This effect was also apparent in regions with 

organized markets. Although market activity as measured by 

transactions reported to the trade press began to increase 

slightly towards the end of the assessment period in some 

regions, it did not approach the levels of prior periods. 

The decline was likely the result of the reduced number of 

creditworthy trading participants and may also be the result 

of a decline in wash trading. Later in the assessment period, 

transactions on ICE rebounded more strongly, particularly 

in regions without organized markets. The very low number 

of transactions reported in Florida may be due to the high 

concentration of the market. Market participants may find 

little value in reporting to the trade press because the 

Figure 27: Price volatility increases in most regions without organized markets.

Note: Data are day-ahead on-peak prices. Annualized historical volatility is calculated as the standard deviation of logarithmic returns, log 

(pricet /pricet-1), where standard deviation is based on all on-peak days (weekdays excluding NERC holidays) during the period. *There is no 2001 

volatility calculation because Florida prices were intermittently reported prior to January 2002. 

Source: Platts Megawatt Daily. Analysis and graphic by OMOI.

Table 12: Reported trading volumes in regions without organized electricity markets.

Average daily

volumes (GWh)

Entergy Florida Cinergy SPP North Palo Verde Mid-Columbia

MWD ICE MWD ICE MWD ICE MWD ICE MWD ICE MWD ICE

2001 (full year) 69 43 1 N/A 180 128 6 N/A 17 10 16 6

2002 (full year) 54 73 2 N/A 127 193 5 N/A 22 32 26 42

2003 (first half) 13 30 0 N/A 61 130 0 N/A 11 22 19 33

Note: ICE did not report trade volumes for Florida or SPP North. Megawatt Daily volumes reflect on-peak transactions surveyed by the trade publication. Megawatt Daily data have been modified to make them comparable to ICE data. Megawatt Daily volumes have been multiplied by 16 to convert 

from a 16 peak-hour MW contract into a MWh. Final volumes are converted to GWh. In addition, since Megawatt Daily volumes include both buy 

and sell sides of transactions and ICE volumes include only the sell side of transactions, ICE volumes were doubled.

Source: Platts Megawatt Daily and ICE.
S T A T E O F T H E M A R K E T S

47

Figure 28: Reported trading volumes decline in regions without organized markets.

prevailing price is revealed through transactions within a 

small pool of counterparties. 

Regions without organized markets lack any 

market-based approach to managing congestion. In the 

Eastern Interconnection, system operators use TLRs. TLRs 

are called when electricity flows exceed permitted levels 

to preserve the reliability of the electric transmission 

system. TLRs interrupt specific transmission flows or 

transactions and may curtail service to specific customers 

or future transmission schedules. The TLR procedure 

addresses reliability concerns and relies on administrative 

procedures rather than market mechanisms to control 

transmission flows. The procedure is not efficient, either 

in terms of minimizing flow needed to resolve constraints 

or of minimizing the economic cost of redispatch. It is 

also not administered uniformly, making congestion 

assessment extremely difficult outside RTOs and ISOs.86

Note: ICE did not report trade volumes for day-ahead power for Florida and SPP North. Megawatt Daily volumes reflect on-peak transactions surveyed by the trade publication. Megawatt Daily data have been modified to make them comparable to ICE data. Megawatt Daily volumes have been 

multiplied by 16 to convert from a 16 peak-hour MW contract into a MWh. Final volumes are converted to GWh. In addition, since Megawatt Daily

volumes include both buy and sell sides of transactions and ICE volumes include only the sell side of transactions, ICE volumes were doubled.

Source: Platts Megawatt Daily and ICE. Analysis and graphic by OMOI.

86 Regions with organized markets and within the Eastern Interconnection 

may call TLRs, but do so rarely because their LMP system prevents most 

congestion from rising to a level that necessitates calling a TLR.
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

48

In addition, the transmission system carries significant 

baseload power on many of the paths flowing from eastern 

parts of the service area, where baseload coal generation 

is located, to western population centers. The paths that 

carry these flows are heavily loaded, but less subject to 

variation in flow and flow overloadings than paths in the 

Eastern Interconnection. As a result of these differences, the 

Western Interconnection did not develop a TLR congestion 

management system, but instead developed separate 

procedures for rating major transmission paths, determining 

transmission capacity on these paths, developing and 

adjusting interchange schedules between control areas 

and curtailing schedules when line limits are exceeded. 

While these procedures resemble TLRs in the Eastern 

Interconnection by relying on an uneconomic curtailment of 

transactions in real-time, they differ in the specifics and are 

not uniform across the Western Interconnection.

Regions without organized markets in both the Eastern 

and Western Interconnections have costs associated with 

the inability of lower cost generation to get to market that 

are not explicitly priced but are borne by customers in the 

region. In the Eastern Interconnection, TLRs curtail transactions, often forcing higher cost generation to be used than 

would be the case under a market-based system. During 

the assessment period, these curtailments and costs rose 

relative to the prior period. In the Western Interconnection, 

operation of phase angle regulators (sometimes called phase 

For the period July to December 2002, the MISO independent market monitor estimated that optimal redispatch 

based solely on flow (as under an LMP system) could be used 

far more efficiently than the TLR system that was used. 

Flow-driven redispatch would relieve congestion with 30 

percent fewer MWs redispatched; economic redispatch would 

relieve congestion with 38 percent fewer MWs redispatched.87

Figure 29 compares the total number of hours of 

high-level (Level 3, 4 and 5) TLRs called in the years ending 

June 31, 2002 and June 31, 2003. TLRs, which are used 

to respond to congestion in real time, increased in all 

regions. However, because different regions in the Eastern 

Interconnection use different procedures for scheduling 

power and managing congestion prior to real time, comparing levels of TLRs across regions does not provide an 

accurate reflection of overall congestion in a region. 

Regions without organized markets in the Western 

Interconnection do not use TLRs to manage congestion, 

partly due to regional system conditions. The Western 

Interconnection uses the procedures of the Western 

Electricity Coordinating Council (WECC) to schedule 

transactions, determine transmission line and path ratings, 

and curtail transactions when needed to maintain reliability. 

The procedures differ from the NERC procedures in 

the Eastern Interconnection, reflecting geographic and 

system condition differences in the two interconnections. 

The Western Interconnection service area is less densely 

populated than the Eastern Interconnection, carries power 

over longer distances, and is more subject to voltage and 

stability constraints than the Eastern Interconnection. 

Figure 29: TLR activity increases in most regions.

Note: 2001–02 includes TLRs during the 18-months prior to the 2002–03 assessment period. 

Source: FERC analysis of data and past events from NERC’s Central Repository for Security Events. Graphic and further analysis by OMOI.

87 MISO, “2002 State of the Markets Report,” prepared by Potomac Economics 

Ltd., independent market monitor for MISO, May 2003.
S T A T E O F T H E M A R K E T S

49

shifting transformers) and generator ramp downs may have 

sometimes prevented lower cost generation from getting to 

market. Phase angle regulators control transmission flows 

to address local overload problems and unscheduled flows 

across the system and ramp downs are called by security 

coordinators to manage congestion. 

To the extent information is available, we consider the 

specific electricity price performance over the assessment 

period in each of these bilateral markets separately.

Southeast

Prices in the Southeast (excluding Florida) remained 

low during the assessment period, as represented by the 

Entergy pricing point, which is the most liquid point in the 

region. Prices at Entergy tended to range from $20 to $40/

MWh, with somewhat higher prices occurring in the summer 

and during the natural gas price spike in February/March 

2003 (see Figure 26). These remained quite stable, with a 

comparably low level of volatility and a modest correlation 

to load. In spite of the high proportion of coal and nuclear 

powered generation (84 percent of the production during 

the period), gas was the marginal fuel 58 percent of the 

time (see Figure 4) and led to a strong correlation between 

natural gas prices and power prices (see Figure 30).

Moderate weather conditions and high reserve margins 

contributed to the low price levels experienced over the 

period. Available resources were added faster than load grew. 

Reserve margins reported by SERC ended the period at 17 

percent, however, merchant generation in the region was not 

included in this calculation unless the load-serving entity 

has a contractual arrangement with the merchant plant, and 

the capacity was reported through the EIA-411 reporting 

process.88 If all the assets in the region were included, the 

total generation would exceed the load by approximately 

65,000 MW, or 41 percent. This results in a total connected 

generation capacity that exceeds the projected load growth 

for the region through 2012.89

Florida

Power prices in the Florida bilateral market generally 

remained moderate and stayed within the range of $25 to 

$60/MWh on more than 90 percent of the reported trading 

days (see Figure 26). Prices exceeded $100/MWh on one 

occasion, during the February/March 2003 gas price spike. 

There was moderate price volatility and prices responded 

to load and fuel input prices as expected and showed a 

significant correlation to gas prices. This can be attributed 

to the significant amount of gas-fired generation capacity 

that operates at the margin in this region. An unseasonably 

warm winter and inexpensive natural gas kept average prices 

below $30 during January and February 2002. A May 2002 

heat wave created unprecedented loads at a time when some 

generation was unavailable because of seasonal maintenance, 

causing brief prices spikes. Hot weather in July and August 

2002 maintained prices levels in the $55 range. Late in 

winter 2002–03, high natural gas used for electric generation 

prices caused an extended period of higher electricity prices.

Figure 30: Entergy electricity prices correlate with natural gas prices.

Notes: Power price point is Entergy. Gas price point is Henry Hub.

Source: Platts Gas Daily and Platts Megawatt Daily. Analysis and graphic by OMOI.

88 SERC, Reliability Review Subcommittee’s 2003 Report to the SERC 

Engineering Committee, June 2003. 89 SERC, Reliability Review Subcommittee, Presentation of Generation 

Development Survey Results: SERC EC-OC-MIC Spring 2003 Meeting, 

March 13, 2003. 
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

50

Midwest

Bilateral prices in the Midwest were higher in the 

12 months ending June 30, 2003, than in the previous 12 

months, but they tended to remain in the $20–$40/MWh 

range throughout most of the year (see Figure 26). In 

addition, volatility remained constant in the Midwest 

over the past five years with the exceptions of some short 

stretches in June 199890 and summer 1999 when prices 

spiked more than 350 percent. 

The region is heavily reliant on coal-fired generation, 

accounting for approximately 77 percent of all Midwest 

generation in 2002. Natural gas was on the margin less 

than in other regions, between 10 and 23 percent, and 

units operating on natural gas accounted for 3 percent 

of generation. However, units operating on natural gas 

represent the majority of new generation being built. In 

general, the region has a relatively large capacity reserves 

margin that exceeds 20 percent in most areas. However, 

there are congested areas within the Midwest, most 

notably, the Wisconsin-Upper Michigan subregion (WUMS). 

Congestion in the WUMS area is in part due to transmission 

configuration changes and a weak transmission interface. 

Because of the relatively large capacity reserves margin 

and the minimum amount of natural gas-fired generation, 

natural gas units are infrequently used to meet native load. 

However, as shown in Figure 31, during summer 2002 and 

in February/March 2003, power prices approached and 

briefly exceeded $100/MWh, indicating that the operation 

of a natural gas generator may have been economical. This 

high price might suggest that natural gas units were on the 

margin, or it could reflect the opportunity cost of a less 

expensive unit selling its power outside the Midwest region. 

Since MISO is in implementation phase, market information 

is sparse. The lack of information makes it difficult to discern 

whether the high prices experienced during this assessment 

period were determined by the internal dispatch of gas-fired 

units or a premium paid by external demand in relatively 

more expensive areas. 

South Central

Daily spot prices in the South Central region ranged 

from $30 to $50/MWh between January 2002 and June 

2003 and reached $190/MWh in late February and early 

March 2003 when natural gas prices spiked across the 

country (see Figure 26). Volatility generally is greater when 

reserve margin limits are approached and in this region the 

reserve margin increased from 2002 into 2003. Daily spot 

prices in the region were stable during this period with the 

exception of two periods of heightened volatility. The first 

was in July and August 2002 which reflected hot summer 

temperatures and corresponding high demand. The second 

was in February and March 2003 when gas prices spiked 

across the country.

90 The 1998 spike was due to generation outages (both planned and 

unplanned), unseasonably hot temperatures (that were not forecasted), 

transmission constraints, opaque and delayed market information systems, 

and lowered market confidence due to sales contract defaults. (See FERC, 

“Staff Report to the Federal Energy Regulatory Commission on the Causes 

of Pricing Abnormalities in the Midwest during June 1998.”)

Figure 31: Midwestern power price spike may make gas-fired units competitive.

Note: Power price point is ComEd; gas price point is Chicago Citygate.

Source: Platts Megawatt Daily and Platts Gas Daily. Analysis and graphic by OMOI.
S T A T E O F T H E M A R K E T S

51

Prices responded to load and fuel input prices as 

expected. Power prices showed a significant correlation to 

gas that remained consistent, regardless of season, and was 

largely attributable to the amount of gas-fired generation 

capacity that operated at the margin. Combined with an 

unseasonably warm winter and inexpensive natural gas, 

this kept average prices between January and late-February 

2002 close to $30/MWh. As in the other regions, high fuel 

prices as well as transmission congestion (evidenced by TLR 

activity) caused an extended period of high electricity prices 

late in winter 2002–03.

Southwest

Market participants are limited to surveyed price 

information for two locations in the region, Palo Verde and 

Four Corners (for Palo Verde price information, see Figure 

26). The Southwest does not have intraday price information. 

Volatility of daily spot prices in the region decreased since 

the energy crisis in the West when prices averaged well over 

$100/MWh and peaked at $539. Excluding prices from the 

February/March 2003 price spike, daily spot prices at Palo 

Verde averaged $38 during 2002 and the first half of 2003. 

The peak price of $118 during the February/March 2003 

price spike was less than average Palo Verde electric prices 

during the energy crisis in the West.

During 2002 and 2003, Southwest spot prices reflected 

a less strained market than in 2001 due to improved reserve 

margins. The additional 8,420 MW of new generation that 

came on line in the region easily outstripped load growth 

due to weak to modest economic growth. However, prices 

for Southwest-traded electricity followed the February/March 

2003 natural gas price spike because most of the new 

capacity added in the region was gas fired.91

The new units were generally not located in urban 

areas experiencing the most rapid load growth, such as Las 

Vegas and several cities in Arizona. Therefore, the urban 

load pockets continued to have problems getting access to 

the lowest cost available power in the region. The bilateral 

pricing points for the region, Palo Verde and Four Corners, 

did not signal this location-specific need. In fact, more generation was built at Palo Verde than the transmission system 

could accommodate, reflecting a disconnect between the 

interconnection process and a regional transmission plan.92

Northwest

Daily spot prices in the Northwest were less volatile in 

2002 and first half of 2003 compared with the preceding two 

year’s energy crisis in the West. During the review period, 

Mid-Columbia daily spot prices averaged $24/MWh and $40/

MWh, in 2002 and first half 2003, respectively (see Figure 

26; see Appendix 6 for approximate price point locations). 

Similar to the Southwest, prices during the February/March 

2003 price spike ($113/MWh) were less than average prices 

seen during the years 2000 and 2001. In addition to daily 

electricity prices surveyed and published by the trade press 

for the California-Oregon Border (COB) and Mid-Columbia 

pricing hubs, Northwest market participants had limited 

access to intra-day electricity prices through ICE, which 

posted hourly prices as traded on its platform. 

The system stresses of the energy crisis had dissipated 

by 2002. Load increases were served with the 4,019 MW 

of new capacity brought on line during 2002 and 2003. 

In addition, hydroelectric generation in the Northwest 

produced 32 percent more energy than in the extremely dry 

2001. Northwest market prices during 2002 and 2003 were 

consistent with the expected effect of improved hydroelectric 

conditions. Market prices tended to decline, reflecting lower 

hydroelectric opportunity costs. During seasonal periods of 

low water flows and reduced hydroelectric output, market 

prices reflected to a greater degree the higher natural gas-fired 

generation prices seen in the other regions of the West. Sixty 

percent of the electricity consumed in the region during 2002 

was generated at hydropower plants, 31 percent was generated at coal-fired power plants and 4 percent was generated 

at natural gas-fired plants. Thus, with low installed amounts 

of natural gas-fired generation, and given a limited potential 

frequency of the natural gas-fired plants in the Northwest to 

set market prices (i.e., times of low, but non-zero hydro energy 

export availability), the Northwest market prices appeared 

to reflect the opportunity costs the resources in the Pacific 

Northwest had for trading elsewhere in the West.

Long-term Markets

The ability to enter into forward contracts is an important 

aspect of well-functioning markets. Forward contracting 

provides a risk management tool that allows market participants to reduce exposure to changing market prices. Forward 

contracting, whether standardized in futures markets or 

customized through bilateral contracts that are physical or 

financial, is a source of price discovery and offers both signals 

and contractual support for long-term investment. Prices for 

long-term forward markets are based on the interplay of shortterm or current prices, and expectations of future demand, 

supply and market conditions for a given commodity. Forward 

prices can be observed in price curves on exchanges such as 

Nymex and ICE, as well as in bilateral markets. 

91 Platts POWERdat, Modeled Production-Cost dataset, EIA Form 906, EIA 759 

and FERC 423. Baseload generation is largely coal in the Southwest as 62 

percent of the electricity consumed in the region was generated at coalfired plants. 92 Arizona Corporation Commission, Second Biennial Transmission 

Assessment 2002-2011, Docket No. E-00000-D-02-0065, December 2002. 
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

52

Table 13: Short-term and long-term contracting by region.

Contracting by region:

Short term Long term

000 GWh Share 000 GWh Share

Regions with 

organized markets

ISO-NE

 ISO-NE 219 69% 69 22%

NYISO

 NYISO 79 72% 19 18%

PJM

 MAAC 475 61% 201 26%

ERCOT

 ERCOT 62 77% 18 23%

CAISO

 CA-MX 258 77% 55 16%

Regions without 

organized markets

Southeast

 SERC 100 56% 67 38%

Florida

 FRCC 2 30% 5 69%

Midwest

 ECAR 233 70% 87 26%

 MAIN 42 20% 162 79%

 MAPP 39 86% 5 10%

South Central

 SPP 8 30% 18 69%

Southwest

 RMPA 3 41% 3 45%

 AZ-NM-SNV 87 79% 17 16%

Northwest

 NWPP 102 73% 32 23%

Note: In the EQR, companies report wholesale power sales within FERC’s jurisdiction. Generation to serve one’s own load, sales by federal authorities such as TVA and BPA, sales occurring fully within ERCOT and sales by qualifying facilities (QFs) under QF contracts are not included. Filings 

with clear errors affecting total sales were eliminated from the dataset pending correction from the submitting company. Regional allocation of sales 

was estimated using Point of Delivery Control Area and Specific Location information provided in the filings. All sales to ISOs were assumed to be 

short term and to occur within the ISO’s control area. Percentages may not sum to 100 percent because some contracts are not defined in the EQR 

database or are not defined as either “long term” or “short term.” 

Source: Derived from FERC EQR, Fourth Quarter 2002 through Second Quarter 2003.

As seen in Table 13, although there is wide variation 

across regions, it appears that customers in regions with 

organized markets on average used a somewhat lower 

percentage of long-term contracts in their supply portfolios 

than in regions without organized markets, 22 percent and 

36 percent respectively. Reports from three regions without 

organized markets indicate a relatively significant reliance 

on long-term contracts. Reported sales in FRCC were 69 

percent under long-term contracts, 69 percent in SPP and 

79 percent in MAIN. 93 Across all regions, approximately 28 

percent of reported U.S. sales are delivered under long-term 

contracts of one year or longer. Despite significant reliance 

on long-term bilateral electricity contracts, there is limited 

forward price transparency to facilitate this contracting.94 

Futures markets for electricity were not available during the 

assessment period, with the exception of the PJM Western 

Hub contract introduced in April 2003.

93 Derived from FERC EQR, Fourth Quarter 2002 through Second Quarter 

2003. For more information on EQR data used in this report see footnote 5. 94 Not all long-term contracts rely on long-term pricing. Many contracts reference short-term price indices. 
S T A T E O F T H E M A R K E T S

53

Market Design and 

Price Transparency

Market designs varied from region to region during the 

assessment period, affecting the efficiency of electric market 

price outcomes. Several of these issues were raised in the 

market-by-market assessments above, but four aspects of 

market design are important to consider in greater detail:

 Price Transparency

 Economic Dispatch

 Seams and Geographical Variations

 Electricity-Natural Gas Interface

Each of these structural issues played out differently, 

with different effects on electric market performance. We 

consider them in turn.

Price Transparency

A transparent market is structured to provide market 

participants with easy access to each other, to products and 

to the price information needed to make efficient buy and sell 

decisions on a timely basis. Participants in wholesale electricity 

markets need to know what the prevailing price is, have an 

understanding of the process by which the price was formed 

and have a certain level of confidence that the price formation 

process is both credible and representative of the population 

of transactions taking place in the region. The scope and 

quality of available price information affects the ability of the 

market to produce a competitive outcome.

During the assessment period, about 65 percent of 

reported sales in the United States were for short-term 

energy,95 but only a subset of these transactions was used to 

develop market pricing. Short-term transactions in ISO or 

RTO markets are systematically used to form market prices. In 

contrast, a subset of short-term bilateral transactions is used to 

develop various index published prices. 

A key distinction between strictly bilateral and organized 

markets is the process for price formation and publication. It 

is the nature of electricity that minute-to-minute variations 

in demand, lack of electricity storage and lack of customer 

response to changing price conditions leads to wide variations 

in spot prices throughout the day. Customers within regions 

with organized markets have the opportunity to purchase 

electricity by the hour for the next day (day ahead) and in real 

time in open, transparent markets that provide explicit information on the locational price of energy, congestion and losses 

in each hour (often more frequently) of the day. Real-time and 

day-ahead prices for physical electricity are made transparent 

through the market-clearing prices posted on ISO or RTO 

websites. Day-ahead market prices are posted on the ISO or 

RTO website shortly after trading closes on the day prior to 

operation and delivery. Real-time prices are posted on the ISO 

or RTO website in almost real time. Although ISO day-ahead 

markets are a competitive alternative to day-ahead bilateral 

contracting, they also provide hourly options and pricing not 

available for most widely published bilateral contracts. 

In contrast to hourly or more granular deals for ISO 

and RTO markets, customers in regions without organized 

markets purchase a block of 16 hours of on-peak (or off-peak) 

energy at a single price. Market participants can discover 

price terms for day-ahead electricity traded bilaterally at 

designated trading hubs by subscribing to trade publications, 

which collect transactional data from market participants to 

produce volume-weighted averages that represent the price 

of a commodity at a particular place and time. These indices 

are published after the end of the trading day. Prices in these 

regions reflect day-to-day and seasonal changes, but not the 

real-time changes in prices that reflect the time-varying cost of 

producing electricity. Confidence in survey-conducted indices 

was eroded early in the assessment period due to revelations 

of wash trading and allegations of misreporting transactions 

to the survey providers. However, even as these activities were 

rectified, structural issues of price opaqueness and inefficient 

dispatch remain. Further, because reporting is voluntary, it is 

not certain that the reported price information is representative of the totality of transactions executed. 

Economic Dispatch

Economic dispatch is a fundamental aspect of market 

design in organized markets. In these regions, prices are 

formed through well-defined regional economic dispatch 

processes.96 The economic dispatch process schedules the 

least-cost mix of generation, based on offered prices, to 

reliably meet forecasted load subject to transmission capacity 

security constraints on economic dispatch. In addition to 

these constraints, most organized markets allow market 

participants to self-schedule their units. Some organized 

markets (e.g., ERCOT and CAISO) limit centralized economic 

dispatch to their real-time markets and rely entirely on 

market participants to optimize schedules in the dayahead market. The economic dispatch process produces 

market-clearing locational prices equal to the marginal cost 

of supplying the next megawatt of energy to a particular 

95 Includes sales made under short-term or spot contracts with terms of less 

than a year. Derived from FERC EQR, Fourth Quarter 2002 through Second 

Quarter 2003. For more information on EQR data used in this report see 

footnote 5. 96 This process is formally termed a bid-based security constrained commitment process that commits and dispatches generating plant in merit order 

(lowest to highest) of supply bids offered to meet forecasted demand with 

the required level of reliability and subject to transmission constraints. 
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

54

location. These prices provide the customer with both the 

current price of energy and the financial effect of congestion 

on the transmission path. 

In regions without organized markets, the price formation process was significantly less transparent during the 

assessment period. Price formation is, in part, a result of 

transmission and dispatch decisions, and the operation of the 

transmission system and dispatch of generating plants in these 

regions was under the control of multiple control area operators. Figure 32 designates control areas across the country with 

white circles. As can be seen, PJM operated two control areas 

and ERCOT operated a single control area. In contrast, there 

were in excess of 20 control areas in the Southeast. 

As Table 14 indicates, in regions without ISOs there 

was not region-wide transmission scheduling or region-wide 

economic dispatch.97 As a result, we cannot conclude that 

the most economic mix of generation in the region, given 

transmission constraints, was dispatched to serve customers 

in every region.

Figure 32: Map of NERC control areas.

Note: Configuration as of August 1, 2003.

Source: NERC

97 A few of the regions without ISOs have hierarchical structures over local 

control areas that coordinate across control areas in a sub-zone of the 

region. For example, Southern Co. and Entergy have centralized operational control over the control areas operated by their subsidiaries.
S T A T E O F T H E M A R K E T S

55

98 Heat rates reflect a measure of generating station thermal efficiency. It is 

computed by dividing the total Btu content of the fuel burned (or of heat 

released from a nuclear reactor) by net kilowatt-hours generated. Note 

that this analysis does not account for startup costs, no load costs or 

operating constraints. 99 Derived from Platts Megawatt Daily information. 100 Covers Arizona, New Mexico and Southern Nevada. 101 Derived from Platts POWERdat information. 102 Derived from FERC EQR, Fourth Quarter 2002 through Second Quarter 

2003. For more information on EQR data used in this report see footnote 5.

Only a few of the control areas in regions without 

organized markets have developed bilateral energy 

trading hubs, and only a few of these involve volumes of 

transactions that can be considered liquid (see Table 12). 

Illiquid trading and infrequently observed prices/trades 

created a non-transparent or opaque market. Further, there 

was only a weak correspondence between the prices at 

these few trading hubs and prices at the generation and 

consumption locations. 

An example of the effect that the lack of locational 

signals associated with economic dispatch may have had on 

efficient operation can be found in the Southwest. Using 

market heat rate analysis,98 OMOI estimated the likelihood 

that natural gas combined-cycle units (assumed to have 

heat rates of 7,000 Btu/kWh) could have been economically 

dispatched at key price points in the United States during 

the assessment period.99 The analysis showed that in some 

markets estimated average capacity factors during the 

assessment period did not match the potential economic 

opportunity of dispatching natural gas combined-cycle plants 

based on the locational price signals indicated by market 

heat rates. For example, capacity factors for natural gas 

combined-cycle plants in the AZ-NM-SNV NERC subregion100

averaged approximately 50 percent during the assessment 

period, even though the average market heat rate suggested 

these units could have been economically dispatched 94 

percent of the time.101

ISO or RTO markets facilitated bilateral market transactions by providing one-stop shopping for energy balancing 

services throughout the region at competitive market prices. 

From the perspective of price formation, these spot markets 

provided a transparent, timely and credible reference price 

for bilateral contract negotiations. Prices and the price 

formation process must be sufficiently visible for market 

participants to decide whether the price is one around which 

they can make deals and enter bilateral contracts. ISO or 

RTO market prices serve as a benchmark and competitive 

alternative to bilateral contracts. For example, in regions 

such as New York, the prices of certain bilateral contracts 

settled at NYISO market prices. Participants in regions with 

organized markets were active in bilateral markets, with 

bilateral short-term and long-term contracts accounting for 

40 to 90 percent of total sales in these regions.102

Effective access to wholesale markets requires timely 

communication of operational information, which is 

essential in markets that must instantaneously adjust supply 

to meet variations in demand. During the assessment 

period, communication of operational information varied 

significantly between regions without organized markets 

and markets operated by ISOs or RTOs. Within organized 

markets, key operational conditions such as the existence 

Table 14: Selected design elements of energy markets, June 2003.

Legend:

  = Yes

  = No

  = Not market based

Regions with 

organized markets

Regions without 

organized markets

ISO-NE NYISO PJM ERCOT CAISO

Southeast Florida MidwestSouth 

Central

SouthServices Provided west North-west

Real-time energy market           

Locational energy price           

Hourly energy price           

Congestion price           

Losses price    (1)   (2)      

Regional transmission scheduling           

Regional economic dispatch     (3)  (3)      

Regional transmission planning           

Regional interconnection process           

Independent market monitor           

Note: (1) Losses are allocated to market participants based on a pro-rata share of total transmission losses. (2) Losses are allocated to sellers using 

generation meter multipliers, which reflect scaled marginal losses. (3) CAISO and ERCOT did not have day-ahead energy markets; economic dispatch was used in their real-time balancing markets only. 

Source: OMOI.
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

56

of transmission congestion were conveyed through market 

prices. When transmission congestion occurs, delivery of 

more power from outside the constrained area is limited. 

Generating plants on the import side of the constraint must 

increase production or generating plants on the export side 

have to decrease production. These production increases 

and decreases are departures from the production schedule 

that is based on the economic dispatch of the lowest cost 

units, resulting in higher costs. When system operators and 

market participants cannot see the cost of congestion, they 

lack locational information that allows efficient dispatch 

and investment. During the assessment period, explicit and 

timely pricing of energy, congestion and losses by organized 

markets provided key information for generator dispatch 

decisions, buy-sell decisions and demand reduction strategies. It also provided information for transmission planning 

and investment decisions. 

In regions where the location and price of congestion 

was not valued and published, the costs were spread to all 

customers regardless of cost causation. In these regions, 

price signals to relieve congestion and improve electricity service were muted or non-existent for transmission, 

generation and demand response operators and investors. 

Without explicit locational pricing of energy and congestion 

in regions without organized markets, we cannot rely on 

markets to identify and address constraints.

Regions with organized markets had responsibility for 

regional transmission planning and generation interconnection. However, where this responsibility was not coordinated 

among control area operators and market participants, or 

did not exist at all, price signals for investment were muted 

or distorted. It cannot be concluded definitively that regional 

planning and interconnection siting would have rationalized the twin problems of generation overbuilding and load 

pockets, because these processes were generally not in place 

at the time development decisions were being made for the 

projects added during the assessment period. However, there 

are several examples of how the lack of locational pricing 

and coordinated regional transmission planning led to excess 

generation where it was not needed, and the lack of transmission facilities to transport electricity to where it was needed.

The experience in the Western Interconnection (which 

includes CAISO, the Northwest and the Southwest) is a case 

in point. Although there was substantial activity regarding 

transmission planning needs underway during the assessment period, the region generally lacked a transparent, 

integrated transmission planning and siting process on a 

regional or subregional basis.103 For example, 8,420 MW of 

new generation came on line in the period in the Southwest. 

Much of this capacity was in excess of the in-region load. 

However, energy exports from the Southwest to load centers 

in California were expected to increase by only 200 MW due 

to transmission constraints.104 Similarly, new generation that 

came on line in Nevada and Arizona could not supply into 

load pockets of Las Vegas and Phoenix in certain hours due 

to transmission limitations. In Oregon and Washington, at 

the “I-5 corridor,” new generation is under construction, but 

with concerns about transmission inadequacy. Additional 

new generation projects may not have been sited in Montana 

and Wyoming—a fuel-rich area—due to transmission limitations on delivering power to the load centers to the West. 

The lack of coordination of generation and transmission 

was also evident in other regions without organized markets. 

Constraints that occurred on the transmission system 

around Atlanta required operational procedures to maintain 

reliability.105 There is also currently a proceeding before the 

Commission regarding Entergy’s process for evaluation of 

short-term transmission requests by generators.106

In summary, customers in regions without organized 

markets had significantly less market information about 

prices, price formation, system conditions and transmission 

infrastructure needs that ultimately affected prices than 

their counterparts in regions with these markets. During 

this assessment period, there was no effective price information regarding the value of electricity over time and across 

locations or of the regional needs for transmission and 

generation siting. This resulted in opaque or non-transparent 

prices, less efficient dispatch of power plants in these areas, 

use of less efficient congestion management tools and muted 

or distorted signals for investment where it was most needed. 

The poor quality of information outside regions with 

organized markets limited the effective functioning of 

wholesale electric markets in those areas—which may have 

ultimately resulted in higher costs to customers.

Seams and Geographical Variations

In a grid system, there are geographical variations in 

electric prices due to differing market rules, generation 

costs, fuel mixes, transmission constraints and other 

considerations. It may be efficient to reduce these 

inter-regional price differences through investment in 

generation or transmission.107 To the extent that these 

103 Transmission facilities provide a service that is regional in nature. 

Transmission characteristics are such that upgrades to transmission facilities 

often support service in areas beyond and far from the local transmission 

facilities. The DOE, in its May 2002 National Transmission Grid Study, 

noted that transmission siting and permitting requires a coordinated 

regional approach since many transmission facilities cross state boundaries 

or land managed by one or more federal agencies. 104 CAISO, 2003 Summer Assessment, Apr. 11, 2003. 105 SERC, 2003 Summer Assessment, May 2003. 106 Docket ER03-1272-000. 107 We will consider the market incentives for investment in a later subsection.
S T A T E O F T H E M A R K E T S

57

differences arise from differences in regulated market 

structures, such as different market rules for scheduling 

and dispatch of power, changes in market rules and 

regulations may be the best way to improve efficiency and 

bring benefits to customers. 

During the assessment period, commerce between 

regions was often constrained by physical grid interconnection limitations. Figure 33 shows day-ahead, on-peak spot 

price differences in 2002 and 2003 for pairs of points from 

neighboring regions that faced these constraints.

During the assessment period, commerce between 

regions was also constrained for non-physical reasons, called 

“seams.” Power products and differences in pricing and 

market rules can differ significantly between ISO and RTO 

markets and result in reduced competition between suppliers across regional boundaries. These differences include:

 Export charges 

 Differences in schedule times, ramp rates and protocols

 Capacity market differences in installed capacity 

(ICAP) definitions, requirements, deliverability and 

recall procedures

In addition, inconsistent treatment of transmission 

service products across multiple control areas, curtailment of 

transactions due to data incompatibilities and inconsistencies 

in ATC calculations and information posting may also reduce 

competition.

Resolving these types of seams differences between 

regions could lower the cost of transacting power sales 

between regions, permit dispatch of lower cost power and 

ultimately lower costs to customers. When neighboring 

regions have RTO or ISO markets, the regions can work 

together to revise rules and to improve market pricing at the 

seams. However, when one region has an RTO or ISO market 

and one does not, efficient pricing becomes more difficult 

to achieve, because there is no organized framework for 

addressing these types of differences. 

Prices at the seam between ISO-NE and NYISO illustrate 

the significance of these seams differences. Figure 34 shows 

the average differences for 2000–2002 between the ISO-NE 

and NYISO when the interface was not congested. The 

consistent year-on-year reductions, from $20.27 in 2000 to 

$10.72 in 2002, indicate significant progress in reducing price 

differences, but the remaining difference of $10.72/MWh in 

2002 still leaves considerable room for improvement. The 

Figure 33: Inter-regional power price differentials vary.

Note: Annual comparisons based on January–September months only. Average 

(including positive and negative values) of day-ahead on-peak prices.

Source: Platts Megawatt Daily. Analysis and graphic by OMOI.
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harmonize market rules, eliminate seams and develop larger 

markets among ISO-NE, NYISO, PJM and the Ontario IMO. 

There are several current open seams projects intended 

to address the causes of these price differences, including 

NYISO real time scheduling (RTS) that will replace existing 

NYISO software and move scheduling toward shorter time 

intervals and greater consistency with the current ISO-NE 

market design. Other projects include improvements in 

reserve sharing and NYISO transmission contract options for 

external interfaces. The NYISO Independent Market Advisor 

has proposed revisions to the regional dispatch, known as 

the virtual regional dispatch (VRD) proposal, where the 

RTOs would adjust schedules in real time to move prices in 

NYISO and ISO-NE closer together. This proposal has raised 

concerns with some participants, but the continuation of 

significant price differences is an indication of the continuing 

need to find better ways to achieve savings through more 

efficient interregional dispatch. OMOI will assess the 

effectiveness of these projects.

Electricity-Natural Gas Interface

As shown in Figure 35, seams also existed between 

natural gas and power markets during the assessment period. 

Owner/operators of gas-fired generating capacity encountered 

transactional burdens because key market rules affecting the 

operations of the gas and power industries were not fully 

aligned. Time periods, for example, defining the “gas day” 

NYISO market adviser estimates that efficient dispatch across 

the seams could have saved NYISO customers $175 million 

per year, approximately 6 percent of their total bill.108

When an ISO or RTO operating an organized market 

with LMP borders an area without an organized market with 

only bilateral trading and transmission pricing based on 

contract path charges, impediments to price convergence 

cannot be addressed by agreements between two ISO/RTOs. 

In these cases, pricing at the interfaces between the regions 

can send misleading signals that do not reflect the actual 

congestion caused by the underlying power trading activity. 

Prices at multiple interfaces can lead to distorted congestion 

pricing and unscheduled flow problems for the importing 

RTO. PJM experienced these problems in 2002 when it 

expanded by adding PJM West, reflected in increased differences between reference prices at the western AEP interface 

and the southern VAP (Dominion-Virginia Power) interface. 

As a result, the range of prices across the interfaces to the 

west and the south increased dramatically from less than 

$1/MWh before the addition of PJM West to $4 and higher 

afterwards. These differences show how the contract path 

approach in neighboring regions can undermine the efficiency of LMP dispatch if LMP pricing at regional interfaces is 

not properly designed. 

The single reference bus pricing approach, now used in 

PJM for the AEP and VAP interfaces to address the problem, 

removes much of the ability to create artificial prices at these 

external locations, but does not fully reflect the corresponding external conditions. Only a single combined RTO or the 

development of a common power market across the region 

would provide that level of pricing accuracy. PJM and MISO 

have begun the development of a common market through 

a joint operating agreement (JOA), which will be in place 

when MISO begins the operation of its organized market. 

For the past several years, the organized markets in 

the Northeast have undertaken a series of projects designed 

to reduce the seams among the RTOs and ISOs, known as 

the Northeast Seams Initiative. This initiative is intended to 

Figure 34: New England-New York price differential narrows.

Note: Average of absolute value of price difference between NYISO and ISO-NE in uncongested hours.

Source: Virtual Regional Dispatch: Concept, Evaluation, and Proposal, Joint Working Paper,

ISO New England, Inc. and New York ISO, Inc., Appendix D, p. 20. Analysis and graphic by OMOI.

108 Based on an estimate for 2002 presented by Potomac Economics to the 

Joint NYISO Market Structure Working Group and the ISO-NE Markets 

Committee, titled “Estimated Savings from Virtual Regional Dispatch.” 

Although prepared as an estimate of savings from Virtual Regional Dispatch, 

this analysis applies equally to any market changes that result in successful arbitrage across the NYISO/ISO-NE seam. The analysis is based on the 

assumption that all customers taking service in the NYISO spot market 

benefit from the pricing improvements. The percentage savings estimate is 

based on the total NYISO spot market receivables ($3.1 billion for 2002) 

reported in the NYISO Monthly Report for July 2003
S T A T E O F T H E M A R K E T S

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and the “power day” varied by market. According to business 

practices adopted by the North American Energy Standards 

Board (NAESB) Wholesale Gas Quadrant Committee and 

incorporated by reference into FERC jurisdictional interstate 

natural gas pipeline tariffs, the term “gas day” always means 

a period of 24 consecutive hours, beginning at 10:00 a.m. 

Eastern Standard Time. However, the definition of the 24-hour 

period comprising the “power day” usually begins around 

midnight and may vary slightly by market. Further, although 

uniform minimum standards exist for when gas market 

participates nominate and schedule gas on interstate pipelines, 

similar standards related to bidding and scheduling power do 

not exist in bilateral markets, ISOs or RTOs.109

Risk Management 

The ability to manage risk effectively is a critical element 

of well functioning markets. Although market participants 

must deal with many different kinds of risks, e.g., price, credit, 

operational and regulatory risks, our discussion focuses 

primarily on price risk management. Risk management in the 

electric markets involves various forms of financial instruments 

for hedging in the long-term bilateral markets as well as 

products offered in the short-term organized markets. 

Price risk management is, in many ways, an explicit 

strategy to manage exposure to volatility. Because 

electricity cannot be stored easily, power prices are 

among the most volatile of all commodities (see Figure 

36). However, annualized volatility declined during the 

assessment period in most major power markets. The 

decrease in volatility was not necessarily a consequence of 

improved price risk management but more likely a result 

of changing fundamentals (e.g., higher reserve margins) in 

power markets. (In contrast, volatility of natural gas prices 

has increased as discussed later in the report.) 

Figure 35: Gas scheduling and power bidding timelines vary.

Notes: All times are Eastern Standard Time.

Source: Based on tariff terms and conditions for FERC-regulated gas pipeline tariffs and ISO/RTOs. Graphic by OMOI.

Figure 36: Power price volatility tops all major commodities.

Note: Annualized historical volatility is calculated as the standard deviation of logarithmic returns, log (pricet /pricet-1), where standard deviation is 

based on all trading days (weekdays excluding holidays) during the calendar year. S&P 500 is provided for comparison.

Sources: Bloomberg, Platts Gas Daily and Platts Megawatt Daily. Analysis and graphic by OMOI.

109 In late 2003, NAESB formed the Gas Electric Coordination Task Force to 

address seams between gas and electric markets.
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The development of risk management options slowed 

after the Enron bankruptcy in December 2001 and subsequent events including accounting and trading scandals, 

credit rating downgrades and price misreporting for 

published indices all contributed to a loss of confidence in 

the industry. Most significant perhaps was the decrease in 

number of creditworthy counterparties. However, there were 

many new developments as well, including the entry of new 

financial players into the business, efforts to address credit 

issues, clarification of rules for mark-to-market accounting, 

new risk management policies (e.g., the CCRO initiative) 

and coordinated efforts between FERC and the CFTC to 

prosecute violators of established rules. 

Organized markets have been helpful in improving 

the choices available for risk management activities. Besides 

offering products such as financial transmission rights (FTRs) 

for managing price risk due to transmission congestion and 

the definition of trading hubs to improve long-term hedging, 

organized markets also offer transparent hourly prices that 

can be used in writing financial swaps. Settlement specifications for financial swaps in organized markets are indexed to 

publicly available day-ahead or real-time prices of the organized markets.110 In regions without organized markets, a 

similar index might only be available from published surveys 

and lacks the same level of confidence and transparency. 

Despite the benefits of organized markets, the lack of 

long-term price transparency remains a problem common 

to both organized and unorganized markets. Even within 

organized markets, the liquidity of forward price quotes can 

vary considerably. Often this depends on the maturity of the 

market and the perceived sense of stability in market rules. 

Forward Contracts

Forward physical and financial transactions for electricity are contracts designed for delivery beyond the day-ahead 

or real-time markets. Forwards are often traded in the OTC 

market using voice brokers or online OTC exchanges like 

ICE, or through direct bilateral transactions. 

With the exception of ICE, there were no transparent, organized markets for transacting physical, long-term 

electricity contracts (typically contracts that cover electricity 

delivery over a period of one year or more) during the 

assessment period.111 Lack of information about long-term 

electricity contracts and prices makes it difficult and costly to 

develop a forward price curve to analyze the profitability of 

potential investments. Forward price curves allow a market 

participant to lock into buying or selling spot energy at a 

future date at the forward price. During the assessment 

period Megawatt Daily did provide long-term prices for 

specific markets, but it is not clear how much volume was 

transacted at these prices. 

ICE also supports trading of financial electricity 

products. During 2003, the primary electricity financial 

product on ICE was a swap during peak hours. A swap is an 

agreement where counterparties exchange a floating energy 

price for a fixed energy price. Swaps are also known as 

contracts for differences or fixed-for-floating contracts. The 

floating price in a financial swap is based on an index. In 

organized markets, spot indices published by the ISO or RTO 

are increasingly being used as the floating index in swaps. 

In unorganized markets, spot indices available from surveys 

may be used or counterparties may prefer to enter into 

forward contracts that do not require an index.

Financial swaps were bid, offered or transacted at 15 

different locations on ICE for a range of tenure from the 

balance of day to the calendar year 2006. ICE does define 

products in regions with and without organized markets. 

The majority of the financial swap volume transacted 

during April 2003 through October 2003112 was at the New 

England pool, New York Zones A (West), G (Hudson Valley) 

and J (New York City) and PJM Western Hub. The financial 

products traded on ICE have been defined at many locations, 

but were transacted primarily at locations where there is an 

organized underlying physical market during the April 2003 

through October 2003 period.

Electricity Futures and Over-the-Counter 

Products on Nymex

Trading of electricity futures contracts remained only 

partially developed during the assessment period. Nymex 

futures contracts for electricity began in March 1996 with 

the Palo Verde (in Arizona) and California/Oregon Border 

(COB) delivery points. The Nymex contracts were originally 

specified with volumetric contract units of 736 MWh of 

electricity.113 For any contracts not closed out prior to the 

monthly expiration, the delivery rate was two MW for each 

on-peak hour. Following the two initial electricity futures 

contracts, Nymex introduced four additional electricity 

contracts between 1998 and 2000. The other futures 

contracts delivery points were Cinergy and Entergy in 1998, 

PJM in 1999 and Mid-Columbia in 2000.

110 Nymex website. 111 Nymex offers a PJM monthly futures contract and New York ISO Zone A 

(West), Zone G (Hudson Valley) and Zone J (New York City) locational 

based marginal pricing swaps. The PJM futures contract and New York ISO 

Zone A, G, and J swaps are offered for a period of more than one year and 

are financially, not physically settled. 112 Although electricity trading was conducted prior to April 2003, the 

volume data for financial transactions available to OMOI at this time 

are incomplete. 113 In 1998, the contract size was changed to 864 MWh. In 1999, the contract 

size was split in half to 432 MWh with an hourly delivery rate of 1 megawatt per hour. The change to 1 megawatt per hour was to make it easier to 

use the contract to hedge standard physical contracts of 25 MW per hour.
S T A T E O F T H E M A R K E T S

61

For several years after the contracts were introduced the 

volume of trading increased. In October 1997, the number of 

Palo Verde futures contracts traded was 110,858 contracts, up 

from 17,548 contracts in 1996. For the same time period, the 

number of COB contracts traded was 83,618, up from 52,346 

in 1996.114 Ultimately, however, the use of Nymex electricity 

futures declined, and did not achieve the same success as the 

Nymex Henry Hub natural gas futures contract. After volume 

in the contracts dried up, all six electricity futures contracts 

were delisted (taken off the exchange) in early 2002. 

There were several reasons for why industry participants may have stopped using the futures contracts. The 

size of the contract specifications did not match well 

against the standard size of wholesale physical transactions. 

The set size of the monthly total number of megawatt 

hours in each futures contract did not account for the 

varying number of peak days in each month. Additionally, 

due to the regional nature of the electricity market, it was 

difficult to use the futures contract delivery settlement 

price plus or minus a basis as a price for other regions. 

This is unlike the Henry Hub natural gas futures contract 

that is used within pricing formulas for regions across the 

country. The electricity futures contracts have to be set up 

for each of multiple regions where there is an underlying 

forward physical market.

After delisting the original electricity futures contracts, 

in December 2002 Nymex proposed three new futures 

contracts at PJM with redesigned contract specifications. 

The contracts are for daily, weekly and monthly periods. 

The three new futures contracts launched in April 2003 

(for the monthly contract) and June 2003 (for the daily and 

weekly contracts) are different from the original electricity 

contracts in two respects. First, the contract size changed 

and second, the contract became financially, not physically 

settled. The daily unit size of the redesigned standardized 

Nymex contract is 40 MWh; the volume for the monthly 

contract must be in multiples of the number of peak days in 

each month. Financial settlement is based upon the arithmetic average of the PJM Western Hub real-time locational 

marginal pricing for the 16 peak hours of each peak day. 

The number of contracts transacted per month and the open 

interest at the end of each month for the PJM Western Hub 

monthly futures contract through October 2003 is shown 

in Figure 37. Figure 38 shows the settlement prices for the 

next-month PJM Western Hub futures contract during the 

assessment period and extending into summer and fall 2003. 

Figure 37: PJM futures volume and open interest increase.

Source: Nymex. Analysis and graphic by OMOI.

114 Nymex, “Nymex Sets Volume Records,” Press release, 10/2/1997.
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In addition to the new electricity futures contract, Nymex 

began clearing standardized electricity contracts in May 2002. 

Credit clearing is a mechanism for settling mutual claims, 

the result of which is that the risk that a company might fail 

to fulfill its contract is pooled among many companies. This 

lowers the risk of entering the transaction, thus reducing the 

cost of the transaction and the credit exposure faced by each 

trading entity. The clearing capability allows market participants to transfer their counterparty credit risk on transactions 

to Nymex.115 During the assessment period, the electricity 

clearing locations included Palo Verde, Mid-Columbia and PJM 

for physical, not financially settled contracts. 

Nymex expanded the list of its OTC electricity locations 

available for both clearing and trading with the start of its 

ClearPort platform in 2003. The ClearPort platform is an 

Internet site where standardized OTC products are cleared 

and specified OTC swaps and futures are both cleared and 

traded. The OTC electricity products that are cleared and 

traded are New York ISO Zone A (West), Zone G (Hudson 

Valley) and Zone J (New York City) locational based marginal 

pricing swaps. The PJM daily, weekly, and monthly futures 

contracts are also available on the ClearPort platform. 

Transactions not executed on Nymex that meet the product 

specifications can also be brought to the ClearPort platform 

for clearing. From May 2002 through October 1, 2003, the 

equivalent of 73.6 million MWhs of electricity has cleared 

through Nymex’s clearinghouse.116 

Next we discuss some of the products and services that 

were introduced for managing different kinds of risk in the 

short term organized markets. 

Virtual Bidding

Virtual bidding is a risk management tool offered in 

NYISO, PJM and ISO-NE to help convergence of day-ahead 

and real-time prices. A virtual demand bid involves a dayahead purchase that is sold back in the real-time market as 

a price taker without any actual consumption of power. A 

virtual supply offer involves a day-ahead sale that is bought 

back in real time without any actual supply of power. In this 

sense virtual bids and offers are essentially financial swaps 

between the day-ahead and real-time prices. 

Virtual bidding allows participants to hedge against the 

risk that real-time and day-ahead prices will differ. Virtual 

bidding eliminates the need to physically withhold supply 

in the day-ahead market if a seller anticipates the real-time 

price to be higher than the day-ahead price. It also allows 

market participants to speculate on the difference between 

day-ahead and real-time prices. Virtual bids and offers 

are open to financially qualified participants regardless of 

whether they own physical assets or have load-serving obligations. Though purely financial, virtual bids and offers do 

affect physical day-ahead energy prices. Accepted virtual bids 

and offers are placed in the day-ahead supply and demand 

curves just like physical bids and offers from generators and 

loads. Other than satisfying the credit requirements, there 

are no barriers to entry for a virtual trader. 

The volume of virtual bidding in NYISO increased 

in 2002 with virtual bids and offers setting price in many 

hours. In ISO-NE, the volume of virtual bidding declined. 

This is partly related to the allocation of PUSH and RMR 

uplift costs to real-time deviations (i.e., the day-ahead 

and real-time price difference must be greater than the 

expected uplift for there to be any incentives for arbitrage 

through virtual bidding). 

Figure 38: PJM futures prices follow seasonal patterns.

Source: Bloomberg, LP. Analysis and graphic by OMOI.

115 Nymex clearing is done via the Nymex Clearing House that is a registered 

Derivatives Clearing Organization with the Commodities Futures Trading 

Commission. 116 Nymex, Press Release, “Exchange Clears 5 Millionth Contract Through 

Nymex ClearPort,” 10/1/03.
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63

Trading Hubs

Fungible long-term products allow for long-term 

hedging to reduce commodity price risk. In order to develop 

standardized trading products in an LMP-based market, 

trading hubs can be defined to foster liquidity in the forward 

markets. In general, the hub price is a weighted average of 

individual node prices. Nodes are typically selected using 

statistical analysis to choose a set of nodes where price 

changes are positively correlated and relatively stable with 

respect to local congestion. The expectation is that by including an average of prices across a large number of buses, 

movements of the price at the resulting virtual hub would 

be more representative of movements of the prices in the 

market. The earliest and perhaps best known example of 

such a trading hub is the PJM Western Hub which consists of 

111 individual nodes. In contrast, the PJM Eastern Hub which 

was defined using similar analysis did not turn out to be as 

widely traded. 

During the assessment period, ISO-NE introduced a 

trading hub (the NEPOOL hub) as it implemented LMP. The 

NEPOOL hub is comprised of a selection of 32 representative nodes: five are 345 kV, one node is 230 kV and the 

remaining nodes are 115 kV buses. The hub price is the 

simple average of the 32 node prices. Experiences with 

this hub were mixed. Prior to the introduction of LMP, 

uncertainty about the hub definition once LMP was implemented appears to have had an adverse affect on liquidity 

in the bilateral markets. Once the LMP-based markets 

commenced operation, there was some congestion within 

the hub that caused ISO-NE to consider re-evaluating the 

hub specification. In many cases, congestion occurred only 

in the day-ahead market, often as a consequence of virtual 

bidding. However, such artificial congestion in the dayahead market that did not persist in real time may be the 

result of ineffective use of virtual bidding. 

Financial Transmission Rights

LMP-based congestion management reduces TLR risk 

and introduces price risks for transmission customers that 

reflect LMP differences between sources and sinks. Unlike 

the exposure to TLRs, LMP-based price risks can be hedged 

through instruments known as financial transmission rights 

(FTRs). There are many different kinds of FTRs which have 

been used in NYISO and PJM for a few years. The most 

basic instrument is a point-to-point obligation where the 

FTR holder either receives or must pay (if negative) the 

LMP difference between pre-defined points of receipt and 

delivery. The payoff for such an FTR would exactly offset 

the price risk for a transaction between the corresponding 

points of receipt and delivery. A point-to-point FTR does 

not necessarily correspond to physical elements of the 

transmission grid. 

Another important type of FTR is a flowgate FTR. 

Unlike point-to-point FTRs, flowgate FTRs are associated 

with actual physical elements of the transmission grid 

and entitle the holder to receive revenues based on the 

shadow prices of flowgate constraints as established in 

the solution to the security constrained unit commitment 

used to set LMPs. While there can be a very large number 

of point-to-point FTRs corresponding to different points 

of receipt and delivery in the transmission grid, the 

number of congested flowgates in any system is typically 

much smaller.117 This can make flowgate FTRs useful 

for facilitating secondary markets. There is little actual 

experience with flowgate-based FTRs except for interzonal 

FTRs in CAISO and ERCOT that are variants of flowgates. 

The Midwest ISO plans to include flowgate FTRs when it 

commences operation of its LMP-based markets. 

FTR options are a form of FTRs that entitle their 

holders to receive only positive revenues (with no liability 

when values are negative). In early-2003, PJM successfully 

conducted an FTR auction where both point-to-point options 

and point-to-point obligations were made available to market 

participants in on-peak, off-peak and 24-hour FTRs. The 

auction had four rounds, and 50 participants submitted more 

than 600,000 bids. 

An important measure of the hedging value of FTRs is 

the level of payout that can be guaranteed once an FTR is 

issued. In general, the revenue collected from LMPs is equal 

to or greater than what is required to pay FTR holders as 

long as the FTR allocation is “simultaneously feasible” with 

respect to the ratings and limits of the transmission system. 

In some instances, these ratings can change after FTRs 

have been issued (e.g., line derates and outages) causing an 

insufficiency in revenues to pay off all FTR holders. In some 

markets (e.g., NYISO), full payout is guaranteed but requires 

market participants to pay an uplift. In other markets (e.g., 

PJM), the payout of FTRs is reduced proportionally. In 2002, 

PJM FTRs had a payout of approximately 95 percent, which 

was slightly higher than the payout in 2001.

Table 15 summarizes key design elements in the 

different FTR markets that are currently in operation or are 

under consideration.

117 In an N node network, there can be as many as 2N (N-1) point-to-point 

FTRs for N > 2. Thus for a 100 node network, there can be 19,800 possible 

point-to-point combinations for FTRs.
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64

42 percent of new capacity installed from 1998 through 

2002.119 Investors and not end-use customers assumed 

the risks in the search for attractive returns, which were 

largely unrealized on these unregulated generation 

investments during the assessment period. 

Generation investment increased reserve margins 

lowering the capacity prices that typically provide a 

significant proportion of generator revenues.120 In 

addition, in a market with stable or declining electricity 

prices, gas price increases led to lower spark spreads for 

many gas-fired generators, cutting net revenues from 

energy sales. As a consequence, revenue tests conducted 

based on observed energy prices in 2002 and 2003 

indicate that new investment would not have been, or 

would have been marginally, profitable in most regions. 

Nevertheless, in certain load pockets, prices continued to 

signal the need for new construction. 

Several factors affect investment decisions and the 

returns on investment in the electric sector including: 

RTO Credit Policies

Credit risk management in organized markets has 

evolved with special credit requirements for some products, 

e.g., virtual bidding and FTRs where the holder may have 

to pay the RTO or ISO if LMP differences are negative. 

In general, however, credit risk in organized markets is 

socialized where shortfalls after default are allocated among 

the remaining participants in a pre-determined manner. 

Due to the shortcomings of this approach, some RTOs and 

ISOs have begun looking at alternatives such as credit risk 

insurance, accelerated cash settlements and other solutions 

to deal with shortcomings of the current system. The details 

of credit policies in RTOs and ISOs can vary in terms of 

collateral requirements, credit limits, cure periods etc. The 

credit limits are based largely on historical usage patterns. 

Billing cycles continue to remain a major factor for credit 

requirements in RTO and ISO spot markets.

Infrastructure Investment 

Investment in electric infrastructure increased 

generation capacity by 10 percent from January 2002 

through June 2003. Of the 85 GW that entered commercial operation during the assessment period, 96 percent 

was gas fired.118 Much of this investment proceeded 

based on decisions made during the period of high 

energy prices before the assessment period. Most of this 

investment was made in generation, predominantly by 

merchant companies, with only a small amount made in 

transmission, predominantly by regulated entities. Ten 

of the most active of these companies, which include 

energy merchants and convergence companies, spent 

$28.5 billion to finance construction of 60 GW, or roughly 

Table 15: Design elements of FTR markets.

Market

Physical/

financial Type of FTR

Fully

funded

Level of existing 

contracts Length Initial auction

ISO-NE Financial

Point-to-point and 

point-to-hub 

obligations

Yes Low Single month

Yes with auction revenues allocated to LSEs/

ARR holders

NYISO Financial

Point-to-point and 

point-to-zone 

obligations

Yes Low

Single month, 

whole year and 

multi-year

Yes, with auction revenues allocated to 

Transmission Owners

PJM Financial

Point-to-point 

obligations and 

options

No Low Single month and 

whole year Yes

CAISO (under 

MD02)

Financial (with 

scheduling 

priority)

Point-to-point 

obligations No High Single month and whole year No

MISO (under 

development) Financial

Point-to-point and 

flowgate FTRs, 

options and 

obligations

Yes High Single month and 

whole year No

Source: OMOI.

118 Derived from Energy Information Administration, Form EIA-860, “Annual 

Electric Generator Report.” 119 Deutsche Bank Securities, Factset, includes AES, Aquila, Calpine, Dynegy, El 

Paso, Edison Mission Energy, Mirant, NRG, Reliant Resources and Williams. 120 Typical project finance structures rely on contracted capacity payments 

to pay for fixed project costs including debt service. Capacity markets in 

regions with organized markets saw price declines during the assessment 

period. For example, according to the PJM State of the Markets Report, 

capacity prices fell from $67.20/MW-day to $12.50/MW-day between January 

and December 2002. NYISO estimates that ICAP revenues would have represented 41 percent of the revenues for a 7,000 Btu/kWh generator in Long 

Island from September 2002 through August 2003 and 51 percent of the 

revenue of a New York City generator of the same heat rate, declining from 

52 percent of revenues on Long Island and 61 percent in New York City, 

respectively, from September 2001 through August 2002. 
S T A T E O F T H E M A R K E T S

65

 current and forecasted prices, 

 potential and actual bid mitigation,

 local opposition to construction,

 financial conditions of the developers, and 

 policies of transmission operators.

This section focuses on the price signals markets 

provided during the assessment period for when and where 

investment was needed. It addresses the following areas:

 Generation Investments

 Investment Opportunities

 Investment Opportunities in Load Pockets

 Demand Response as an Investment Alternative

 Transmission Investment

 General Investment Conditions

Generation Investments

Reserve margin and load data suggest that there were 

adequate, or in some cases, excess resources and reserves 

to meet regional demand during the assessment period. 

Reserve margins, which run from a low of 13 percent in 

PJM to 40 percent in the Northwest, are shown in Appendix 

2. However load pockets persisted in subregions where 

the capability to import needed lower cost power was 

significantly constrained, and the overall regional reserve 

margin did not identify such investment requirements. 

Wholesale customers reaped the benefit of the 

surplus generation situation during the assessment 

period through lower and more stable prices. The lag 

time between price signals and the ability to site, license, 

finance and construct new capacity meant decisions made 

by producers based on price signals sent in 1999 through 

2001 led to capacity additions made during 2002 and 

2003. Adequate, and in some cases more than adequate, 

generating capacity coupled with low demand growth 

resulting from the economic downturn and mild weather 

contributed to lower energy prices in the assessment 

period than in previous periods. 

As seen in Figure 39, about 30 percent of total U.S. 

generating capacity additions during the period was in the 

Southeast. New additions in the Midwest were 17 percent 

of the total, with ERCOT completing about 10 percent 

of total U.S. additions to generating capacity during the 

period. ISO-NE, the Southwest, CAISO and Florida also saw 

significant increases to regional generating capacity. 

In some of these regions, ERCOT and ISO-NE in particular, significant capacity additions were made to already 

comfortable reserve margins (originally 31 percent and 17 

percent, respectively). Some merchant generators assumed 

open access and built capacity, in many cases not due to its 

proximity to load or in areas of low reserve margins, but 

where it was easiest to build, where there was access to gas 

supply or where tax and other incentives were offered. 

Figure 39: New additions increase U.S. capacity by 10 percent.

Source: EIA, Form 860, Annual Electric Generator Report. Analysis and graphic by OMOI.
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66

Merchants owned or operated approximately 85 percent 

of the gas-fired capacity placed into service during this 

period.121 Because the investment was made outside of the 

regulated rate base, investors rather than end-use customers 

bore the brunt of the losses of the “bust” portion of the 

current cycle. As will be seen below, market prices in many 

regions were likely not sufficient in 2002 and 2003 to meet 

equity payments, and in some cases even debt payments, on 

the generation investment. Competitive pressures held down 

wholesale prices. However, the degree to which these lower 

prices accrued to retail customers depends on particular 

state-level regulatory and market structures.

Investment Opportunities 

Prices in well-functioning markets should attract and 

retain needed investment when and where needed. The 

profitability of investment during the assessment period 

varied from region to region and was influenced by market 

design. Net revenue, or estimated market revenue less 

estimated variable operating costs, indicates the extent 

to which markets support recovery of the fixed costs of 

investment and a profit. New investments and operating 

facilities are sustainable when they earn revenues sufficient 

to cover both marginal costs and fixed costs (including 

fixed operations and maintenance costs, interest payments, 

taxes and depreciation) and provide an attractive return 

on equity. Net revenue will vary in the short term due to 

changes in fuel prices, weather, outages, exercise of market 

power or regulatory market power mitigation. Over the 

longer term, revenues will vary as temporary shortages or 

surpluses reflect the entry and exit of generating facilities. 

Thus investors consider the revenue streams over a period of 

time approximating the useful life of the assets (measurable 

in decades) and within the context of the region’s resource 

adequacy.122 Net revenue and spark spread analyses are 

useful investment signals used by market participants in 

conjunction with other analyses, including net present value, 

financing and real option models. While this study concentrates on historical observed prices, investors rely heavily 

upon projected future results based on revenues and costs 

driven by assumptions of future demand and supply growth. 

This growth is affected by changes in regional economies 

and energy intensity, regulatory structures, plant retirements 

and expansions, environmental regulations and the costs of 

equity and debt capital. 

To assess the degree to which electricity markets may 

sustain current investment and attract new entry in regions 

and constrained areas where it is needed, OMOI used three 

market revenue tests:

 OMOI asked the NYISO, ISO-NE, PJM and CAISO 

MMUs to calculate net revenues that a hypothetical 

combined-cycle plant would earn in each market 

during the assessment period region-wide and in 

constrained areas based on locational revenues and 

differences in costs. 

 For regions without organized markets, OMOI conducted spark spread/profitability regional analyses to gauge 

the likelihood that a new, efficient 500-MW natural 

gas-fired combined-cycle plant would be called upon to 

run, and whether revenues would be sufficient to cover 

fuel costs, pay debt service and equity returns. 

 A demand response analysis measured the profitability 

of investment in demand response in both organized 

and bilateral markets.

In the first or net revenue analysis, revenues included 

energy market revenue, capacity market revenue if applicable, ancillary service payments and uplift payments.123

The analysis was performed for system-wide prices and 

for selected load pockets. The net revenue, calculated by 

ISOs for their markets, was compared by OMOI to costs of 

construction estimated by the MMUs for their respective 

markets for a combined-cycle plant ranging from $81 to 

$115/kW-year.124

The results using system-wide prices from organized 

markets are shown in Table 16. Positive values indicate that 

revenues would have been sufficient to cover variable costs 

as well as fixed costs and begin to provide equity returns. 

Negative values indicate revenues insufficient to cover all 

fixed costs. The tests suggest that prices signaled need for 

new construction in CAISO’s regional markets and in NYISO’s 

Hudson Valley region. Prices do not suggest investment in 

ERCOT, ISO-NE or PJM. The test reflects need for projects to 

121 Derived from Energy Information Administration, Form EIA-860, “Annual 

Electric Generator Report.” 122 OMOI’s examination indicated that net revenues in 2001 were higher than 

during the assessment period. OMOI will use this information as a baseline 

for continued monitoring. 123 Energy market revenues are based on region-wide electricity prices and 

the daily natural gas price reported for representative pricing points in the 

region. Capacity payments are based on capacity auction averages; ancillary 

service and uplift payments are estimated as a pro-rata share of the total. 

OMOI provided the MMUs with common assumptions for variable costs 

and operation of a hypothetical combined-cycle unit, including: 7,000 Btu/

kWh heat rate, $1/MWh variable O&M cost, 5 percent forced outage rate 

and unit dispatch whenever LMP is greater than or equal to variable cost. 124 Levelized annual revenue requirements for generators depend on several 

inputs, including: installed cost, project life, debt/equity ratio, tax rate, 

interest rate on debt, return on equity and fixed O&M charges, and these 

vary by location and technology type. Each MMU provided an annual revenue requirement on a $/kW-year basis for a combined-cycle baseload plant 

to derive the net revenues in their markets: PJM provided $81/kW-year, 

ISO-NE, $115/kW-year and the NYISO, $99.50/kW-year for outside of New 

York City. The CAISO provided a range of between $70 and $90/kW-year 

and OMOI has shown the analysis using costs of $90/kW-year for CAISO. 

These figures compare with a national cost of $90/kW-year provided by 

Pace Global Energy Services in Mind the Gap, Project Finance, July 2003.
S T A T E O F T H E M A R K E T S

67

pay off debt service and provide an equity return to signal 

investment, but access to and costs of the capital markets vary 

over time. Under current capital market conditions, lenders 

require revenues that exceed debt service costs by several 

times for projects without long-term fixed price contracts 

earning revenue based on bilateral or spot market sales. Equity 

sponsors may require higher equity hurdle rates.125

Table 16: Profitability indicated for CAISO 

and NYISO investment.

Area

Net revenue in ISO 

day-ahead market 

($/kW-year)

ISO-NE -$18.8

NYISO (Hudson Valley) $35.8

PJM (1) -$9.8

ERCOT -$60.3

CAISO (SP-15) $87.8

CAISO (NP-15) $81.7

Note: Year ending June 30, 2003. Break-even operations would earn 

net revenue of zero. See footnote 124. (1) PJM’s analysis used calendar 

year 2002 data and cannot be directly compared to the other 

regional analyses

Source: ISO-NE, CAISO, PJM, NYISO, ERCOT. 

The second test was spark spread/profitability analysis for 

the regions without organized markets, which, while similar 

in concept to the net revenue test employed for the organized 

markets, relies solely on revenues from energy sales in each 

regions’ spot (i.e., day-ahead) bilateral energy markets.126 This 

analysis assumes that units are dispatched if reported bilateral 

electricity prices exceed fuel costs (based on reported dayahead prices) incurred to run the plant. The resulting market 

revenues generated were compared to a national cost of 

construction benchmark of $90/kW-year. This benchmark does 

not take into account cost differences between regions, which 

can vary from 10 percent to more than twice the benchmark 

cost.127 Results are presented in Table 17.

Table 17: Investment not signaled in regions 

without organized markets.

Area

Net revenue from bilateral market

($/kW-year)

Southeast -$69.5

Florida -$41.3

Midwest -$72.0

South Central -$64.1

Southwest -$30.5

Northwest -$67.3

Note: Year ending June 30, 2003

Source: Platts Megawatt Daily and Platts Gas Daily. 

See footnote 126.

Consistent with high reserve margins and spark spreads 

across much of the country (see Appendix 2), the analysis 

results shown in Table 17 indicate that spot electricity 

revenues were insufficient to support profitable operation 

of a state-of-the-art combined-cycle plant and would not be 

sufficient to attract new baseload generation investment in 

the regions examined.128 The analysis is based on a single 

bilateral price for a block of peak hours region-wide that 

does not reflect variations in costs throughout the day, 

locational characteristics, or congestion values. Thus, the 

price signals in these regions are limited. While there may 

be locations, such as the Atlanta, Las Vegas, and Phoenix 

metropolitan areas for example, within the regions where 

investment should be signaled, transparent locational price 

signals do not exist for these areas, preventing OMOI from 

conducting load pocket-specific analysis similar to those 

conducted for load pockets in regions with organized 

markets presented below. However, many of the same 

(and some different) impediments and incentives to new 

construction exist in these regions, some of which are 

summarized in Table 18.

Investment Opportunities in 

Load Pockets

Several locations around the country need additional 

resources. The need for resources is reflected in market 

prices through locational marginal prices, congestion 

charges and transmission line loading relief. Despite higher 

prices associated with these areas, limited investment in new 

125 Standard & Poor’s, Infrastructure Finance Criteria and Commentary, 

October 2000, as revised and updated at November 2003 in Project Finance 

Conference, New York City. 126 The bilateral electricity prices do not include capacity, ancillary and uplift 

payments as included in the first net revenue analysis. Though generators 

may also earn revenue for providing ancillary services to transmission operators in regions without organized markets, this revenue is not included 

in this analysis because no public data on this revenue stream are available 

for all regions. Analysis based on bilateral trade indices compiled by Gas 

Daily and Megawatt Daily during the assessment period. Debt service and 

equity targets are based on figures reported in Mind the Gap, by Richard 

Ashby and Art Holland of Pace Global Energy Services, published in Project 

Finance Magazine, July 2003. The targets are annualized, low-end figures of 

benchmark ranges for a two-unit, 500-MW combined-cycle plant operating 

4,171 hours annually (on-peak, 5x16 year-round), with a 60-40 percent 

debt-to-equity split, 15 percent after-tax return and 8.25 percent interest on 

debt; the benchmark figures used in this report are not adjusted for possible regional differences. 127 Based on construction cost estimates developed for regions with organized 

markets as detailed in the note on Table 18 and footnote 124. 128 OMOI’s oversight and analysis indicates that despite the economic competitiveness of new gas-fired generation, capacity factors remained low in 

the period despite their low heat rates indicating that new plants may not 

be running as much as they should in these markets based on purely economic dispatch (absent LMP or transmission congestion information). As a 

result, the profitability test may be overstating the run-time and revenues 

generated because it implicitly assumes economic dispatch. 
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

68

generation, transmission or demand response was made in 

several locations: 

 New York City. New York’s installed generating capacity 

has barely maintained the desired 18 percent reserve 

margin over the past several years. Constrained localities 

within the state—New York City and Long Island—have 

been particularly vulnerable to capacity shortages and 

higher prices during high demand periods.

 Areas in New England. ISO-NE has excess capacity system-wide. Areas such as Maine have excess 

generation whereas load pockets such as Southwest 

Connecticut (SWCT) barely meet reserve requirements. 

The most heavily congested areas are SWCT, Northeast 

Massachusetts (NEMA)/Boston (where significant progress has been made), Southeast Massachusetts/Rhode 

Island and Vermont areas. Little of the region’s new generation was located in these areas. Maine, on the other 

hand, benefited from large new generation additions 

but has insufficient transmission capacity to transmit its 

total output to load.

 Areas in California. While substantial new generation 

was added in California, little new generation was built 

in the congested areas of San Francisco, Los Angeles and 

San Diego and they continue to have generation deficits.

 The Delmarva Peninsula. While $58 million was invested in transmission upgrades on the Delmarva Peninsula 

between January 1998 and May 2003, congestion continued to occur in the region in some hours during the 

assessment period. The full effects of the investment 

were expected by PJM in the months subsequent to the 

assessment period.

 Areas around Atlanta, Las Vegas, and Phoenix.

Transmission constraints occurred in these areas 

around growing metropolitan areas in regions without 

organized markets requiring operational procedures to 

maintain reliability, potentially preventing new generation from reaching load.129

With cost, site availability and ease of licensing and 

construction driving much of the generation site selection and 

insufficiently granular locational pricing signals and market 

price mitigation rules dampening incentives, much generation 

investment was made in locations of opportunity rather than 

greatest need, such as load pockets. 

The results of net revenue tests for load pockets diverge 

from those done on a regional basis because generators 

received higher returns stemming from congestion costs in the 

areas but had higher expenses due to the higher costs of operation in the areas as well. Where higher returns outweighed 

higher costs, investment in the load pocket was signaled. The 

analysis attempts to account for differences in costs in the 

load pockets including the potential that siting is generally 

more difficult, environmental limitations more stringent and 

construction costs and operating costs are higher in load 

pockets. The accuracy of these estimates affects the outcomes 

of these net revenue tests.

Results are shown in the first row of Table 18. The test 

indicates building new generation in New York City and Long 

Island would be profitable based on assessment period prices, 

but that there was a low market valuation of building on the 

Delmarva Peninsula. The analysis also indicates that building 

in NEMA or SWCT would not be profitable. In New York City, 

the net revenue test used observed day-ahead prices that were 

frequently the result of bid mitigation, which sent a strong if 

incomplete signal that investment was needed. Given that 

roughly 50 percent of the unit-hour bids in the day-ahead 

market were mitigated in the assessment period, which sent a 

strong if incomplete signal that investment was needed but not 

financially incented, it is surprising that the net revenue test 

found that investment was strongly signaled in New York City 

in comparison to other load pockets. As new investment in 

New York City was needed but not occurring at a sufficiently 

high level, this inconsistent result may be due to inaccurate cost 

estimates, insufficient time for the price signal to be expressed 

in long-term investment, insufficient confidence in the sustainability of the prices, high construction risk or the existence 

of additional regulatory hurdles or mitigation regimes not 

reflected in the observed New York City prices. 

In the case of the Delmarva Peninsula in PJM, where 

revenues are higher than for PJM as a whole, the net revenues 

test indicates investment would be slightly profitable. However, 

without location-specific estimates of the cost to construct and 

operate a new plant in an area with limited fuel supply options 

and constrained transmission facilities (indicating high costs for 

transmission upgrades by a new interconnection), the signal is 

a weak one. In New England the net revenue test indicates that 

investment would not be signaled for either SWCT or NEMA, 

but the signal may be explained partly by the fact that the 

18-month net revenue analysis only includes locational pricing 

signals for four months, three of which are during the shoulder 

period. OMOI will continue to examine ISO-NE load pockets 

to determine if LMP, particularly in summer months, and the 

introduction of locational capacity prices provide stronger 

investment signals. PJM’s analysis used calendar year 2002 data 

and cannot be directly compared to other regional analyses. 

The decision to build new infrastructure in a load 

pocket is affected by several factors in addition to expected 

net revenue. Table 18 examines whether a set of factors 

are a relative incentive or impediment to investment in the 

129 SERC, 2003 Summer Assessment, May 2003. Second Biennial Transmission 

Assessment 2002-2011, Arizona Corporation Commission, Docket No. 

E-00000-D-02-0065, December 2002. Order, Public Utilities Commission 

of Nevada, Docket No. 02-11015 (www.puc.state.nv.us/ELECTRIC/dkt_02-

11015/02-11015o.pdf) Oct. 15, 2003.
S T A T E O F T H E M A R K E T S

69

Table 18: Net revenue tests suggest investment in New York City, Long Island and Delmarva load pockets. 

  = Relative 

Incentive

  = Relative 

Impediment

  = Neutral

Load pockets in regions with 

organized markets

Load pockets in regions without 

organized markets

ISO-NE 

(SWCT)

ISO-NE 

(NEMA/Boston)

NYISO (Long 

Island)

NYISO 

(NYC)

PJM

(Delmarva)

Southeast 

(Atlanta)

Southwest 

(Las Vegas)

Southwest 

(Phoenix)

Net revenue ($/kWyear) (1) -$15.7 (2) -$20.0 (2) $9.7 $82.6 $4.1 N/A (3) N/A (3) N/A (3)

Siting and 

environmental 

permitting



Limited site 

availability



Limited site 

availability





Limited site 

availability; high 

costs



Limited site 

availability

  

Ease of 

interconnection        

Transmission 

infrastructure



System cannot 

support 

expansion or 

simultaneous 

operation 

of existing 

generation at 

full load



Insufficient 

transfer 

capability within 

the Boston area 

and insufficient 

import 

capability



Physical 

constraints 

into Long 

Island

 

Physical 

constraints 

into (incentive) 

and within 

(impediment) 

NYC



Insufficient 

import 

capability

  

Transmission 

availability (shortterm dispatch)

       

Fuel supply   



Limited pipeline 

capacity



Limited pipeline 

capacity

  

Locational energy 

pricing



Began March 

2003



Began March 

2003

   

Not available



Not available



Not available

Locational capacity 

pricing



Does not 

currently exist



Does not 

currently exist

   

Not available



Not available



Not available

Economic dispatch        

Regulatory—

market design risk  



Loss of Article 

X siting law



Loss of Article 

X siting law

   

Mitigation regime



Reference 

prices may 

prevent 

recovery of 

fixed costs



Reference 

prices may 

prevent 

recovery of 

fixed costs



Conduct and 

Impact &

Alternate new 

gen reference 

price

 

Energy prices 

mitigation 

(impediment) 

Alternate new 

gen reference 

price (incentive)



Uncertainty on 

applicability to 

new gen

Not 

applicable

Not 

applicable

Not 

applicable

Reserve margins        

Financing and 

financial strength 

of merchants



Weak 

merchants



Weak 

merchants

  



Weak 

merchants

 

Note: Year ending June 30, 2003. Break-even operations would earn net revenue of zero. (1) Energy market revenues are based on an LMP or a 

zonal market-clearing price, reflecting higher costs in congested areas. ISO-NE provided the same costs of $115/kW-year for SWCT and for NEMA 

as for ISO-NE as a whole. PJM did not provide a separate revenue requirement for the Delmarva Peninsula. OMOI used the PJM-wide cost for the 

Delmarva Peninsula, which likely understates costs and overstates net revenues. NYISO provided a combustion turbine cost in NYC of $180/kWyear. Based on additional analysis, we adjusted the cost of a combined-cycle upwards to $225/kW-year due to higher capital costs, and applied this 

cost to both New York City and Long Island. It is likely that this overstates costs and understates net revenue on Long Island. Other assumptions 

mirror those used in regional net revenue analyses. (2) LMP was only in effect for four months during the assessment period, beginning March 1, 

2003. (3) Not available as net revenues not measurable based on LMPs in these bilateral markets. 

Source: Revenues supplied by ISO MMUs. Costs based on MMUs and FERC analysis. 
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

70

identified load pockets. Mitigation is often applied in load 

pockets because of the greater potential for the exercise 

of market power in a constrained market. An unintended 

consequence of such mitigation can be the muting of 

investment signals through the suppression of prices. In 

depressing revenues, mitigation also diminishes returns 

on investments once made. Where signals to build in load 

pockets are communicated by price signals from organized 

markets, the signals may not have been acted upon in load 

pockets due to difficulty and timing of siting plants and 

obtaining environmental permits, high costs of construction, 

the financial weakness of merchant participants or 

uncertainty concerning changes in market structure and 

mitigation regimes. A generation owner’s ability to re-power 

existing fossil and re-license existing nuclear plants also 

could negatively affect investment. In regions without 

organized markets, while transmission constraints may exist, 

investors may confront a lack of locational price signals that 

value these constraints and concerns about interconnection 

and economic dispatch.

Demand Response as an 

Investment Alternative

Demand response, an effective tool for dampening 

price spikes and protecting reliability, was largely missing 

from electricity markets during the assessment period. 

Lack of demand responsiveness to price harms competitive 

wholesale markets; however, demand response must offer 

the customer an attractive proposition. To assess whether a 

demand response action taken during the assessment period 

would have been cost-effective, OMOI analyzed the market 

return for a hypothetical customer willing to reduce demand. 

OMOI’s analysis indicates that, given the relatively low 

energy prices during the assessment period, the hypothetical 

customer would have found low or no net benefits from 

the hypothetical demand reduction in most regions of the 

country if based on energy bill savings alone. Energy savings 

would have been sufficient to make demand reduction costeffective for a demand responsive customer in New York City 

and nearly cost-effective in SWCT. 

Customers in NYISO, PJM and ISO-NE have opportunities to participate in ISO or RTO demand reduction markets 

that provide incentives or guaranteed payments for demand 

reduction during emergency periods, and to receive revenues 

in addition to energy savings for providing products such 

as installed capacity and ancillary services. These additional 

revenues improve the cost-effectiveness of demand response 

in these locations if the customer is willing to assume the 

additional associated obligations and penalties for nonperformance, if any. The effect of capacity and ancillary 

services payments on the overall cost-effectiveness of the 

hypothetical demand reduction is also assessed.

For purposes of this analysis, OMOI assumed a hypothetical large industrial/commercial customer who pays retail 

electricity rates tied to wholesale market prices.130 We further 

assumed that the customer would reduce load by 1 MW 

whenever the market price exceeded $50/MWh, and in return 

would avoid paying the energy prices prevailing during the 

hours of the reduction.131 OMOI estimated that the customer 

would need to spend $10,200 to be able to reduce load by 

installing interval meters and other enabling technology.132 

Based on the actual bidding through the NYISO and PJM 

demand response programs during the 18 months ending 

June 30, 2003, OMOI assumed that it would cost the customer 

$50/MWh to run a back-up generator or take other action 

to effectuate the demand reduction.133 In this hypothetical 

scenario, when the market price was $50/MWh, the customer 

would have just covered the variable costs of demand reduction by avoiding energy payments. The customer would have 

had net revenues (energy savings less variable costs) when 

the market price was greater that $50 and would have applied 

these savings to offset the $10,200 investment.134 

As shown in Figure 40, in Zone J (New York City) the 

customer would have fully recovered the fixed costs by early 

2003, as indicated by the height of the blue area (cumulative 

revenues due to energy bill savings) crossing above and exceeding the break-even level represented by the yellow line.135

130 Large commercial and industrial customers in New York, New Jersey and 

parts of Maryland, Georgia and Texas pay retail rates tied to wholesale prices. 131 Energy is a large component of the all-in price of wholesale electricity in 

regions with ISO-operated markets. For example, see Figure 21. Outside 

of regions with ISO-operated markets, only energy prices are visible from 

market price indices. To allow comparisons across all electric regions, 

OMOI’s analysis for this State of the Markets Report focused primarily on 

returns from energy, while indicating where other revenue streams are 

available and likely to affect the cost-effectiveness result. 132 Assumption based on average cost incurred by participants in the NYISO 

demand response programs during 2002 who received NYSERDA matching funds for enabling technologies. Neenan Associates, Lawrence 

Berkeley National Laboratory, Pacific Northwest National Laboratory, How 

and Why Customers Respond to Electricity Price Variability: A Study of 

NYISO and NYSERDA 2002 PRL Program Performance, January 2003. 133 Derived from ISO MMU responses to OMOI Data Request. 134 For the purposes of this analysis, a limiting assumption was made that the 

customer’s core business operations allowed implementation of the demand 

reduction strategy in only 25 percent of the hours when the market price 

exceeded $50. In addition, the customer would not implement the demand 

response action when the market price was less than $50/MWh. 135 The marginal benefit line on Figure 40 shows the difference between the 

prevailing market energy price and the customer’s assumed marginal cost of 

$50/MWh. A negatively valued difference or marginal benefit, which prevailed 

from January through March 2002, indicates that the market price is less than 

the customer’s variable cost and the customer would not have implemented 

demand reduction solely for the energy bill savings. Demand reduction in 

hours with a positive marginal benefit, which prevailed for most of the remainder of the assessment period, would have allowed the customer to fully offset 

variable costs and accumulate funds to pay for the $10,200 investment in 

equipment (the fixed cost target). The cumulative revenue line on Figure 40 

represents the accumulation of energy bill savings that could be applied to pay 

off the fixed costs. 
S T A T E O F T H E M A R K E T S

71

Figure 40: New York City demand response is cost-effective.

Source: Based on price data from NYISO and Platts Gas Daily. Graphics and analysis by OMOI.

Table 19: Demand response cost effective in some key locations.

Demand response would be 

cost effective with:

Energy bill

savings only

Additional capacity or 

ancillary payments

Regions with organized 

markets

ISO-NE

 Mass Hub Close Yes

 SWCT Close Yes

NYISO

 Zone J (New York City) Yes Yes

 Zone A (West) No No

 Zone G (Hudson Valley) Yes Yes

PJM

 PJM Western Hub No Yes

 Delmarva Close Yes

ERCOT

 ERCOT No No

CAISO

 NP-15 No No

 SP-15 No No

Regions without 

organized markets

Southeast

 Entergy No Not Available (1)

 TVA No Not Available (1)

 Southern No Not Available (1)

Florida

 Florida No Not Available (1)

Midwest

 MAPP No Not Available (1)

 Cinergy No Not Available (1)

 ComEd No Not Available (1)

South Central

 SPP No Not Available (1)

Southwest

 Palo Verde No Not Available (1)

Northwest

 Mid-Columbia No Not Available (1)

 COB No Not Available (1)

Note: (1) Mechanism not available for treating demand reduction as a capacity or ancillary services resource. The potential for the customer to avoid 

ancillary service charges under regulated tariffs is deferred for future analysis.

Source: OMOI.
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

72

Using these simplified assumptions, the analysis 

suggests that demand response would have been economic 

based on energy savings alone during the period in New 

York City and New York Zone G (Hudson Valley), and, as 

Table 19 indicates, would have been close in Southwest 

Connecticut and the Delmarva Peninsula in PJM. With additional revenues/savings from capacity or ancillary services, 

demand response would have been cost effective in each of 

these regions as well as in PJM and New England as a whole. 

Demand response based on energy savings alone would not 

have benefited the hypothetical customer elsewhere. 

It is possible that a customer may not need to recover 

all of the fixed costs during the initial 18-month period as 

hypothesized here, and could spread recovery over a longer 

period of time. The lack of a publicly available forward price 

curve for all regions analyzed, such as would be provided by 

actively traded futures or forward contracts, prevents us from 

assessing whether the slower pace of fixed cost recovery 

prevalent in the remainder of the regions would be sufficient 

for a customer with a longer pay-back period requirement.

Transmission Investment

Investment in new transmission facilities was weak 

during the period, with some notable exceptions. While 

transmission costs represent an average 7 percent of total 

delivered energy costs to customers nationally, during the 

assessment period transmission did not receive a commensurate level of investment.136 Transmission investment by either 

regulated or merchant players failed to keep pace with either 

generation or demand growth. While participants made 

large investments in power generation,137 annual growth in 

generation capacity was 2 percent from 1998 to 2001, transmission investment in circuit miles grew less than 0.5 percent 

annually. This trend continued during the assessment period. 

136 EIA Annual Energy Outlook, 2003. 137 NERC 2002 Electric Supply & Demand Database, Edison Electric Institute, 

Cambridge Energy Research Associates, Beware Transmission Data, June 

2003. Includes preliminary data for transmission for 2001, and 2002 for 

new generation capacity.

Table 20: Merchant transmission projects.

Project Capacity (MW) Estimated cost

Original estimated

in-service year

Harbor Cable (NJ, NY) 650 Unknown 2004

Lake Erie Link (Ontario, OH/PA) 975 Unknown 2004

Empire Connection (NY) 2,000 $750 million 2006

Chesapeake Transmission 400 Unknown 2007

Northern Lights (Alberta-U.S.) 2,000 $1.2 billion 2008

Pegasus* (Ontario, Quebec, NY, NJ) 3,000 $1.0 billion N/A

Neptune (NJ, NY) 4,800 N/A N/A

Northeast Utilities (CT, NY) N/A Unknown Project abandoned

Note: *Not filed at FERC.

Source: FERC filings; press releases

Of the transmission projects built in 2002 and 2003, most 

were built by regulated entities. After several years of licensing 

and siting efforts, some projects were approved during the 

assessment period, including a major project in Connecticut 

and several projects to relieve congestion in ERCOT. However, 

the number of approved projects is not as significant as those 

for gas transmission pipelines nationwide. 

There were merchant transmission developments and 

independent transmission company formations during the 

assessment period. One merchant transmission project 

was built during the period, seven received FERC approval 

and two received partial development or full construction 

funding. The 330-MW Cross Sound Cable, a merchant 

direct current (DC) transmission line, was laid underwater 

between Connecticut and Long Island and financed based 

on the credit of a long-term contract with Long Island Power 

Authority (LIPA), which LIPA signed after winning a competitive auction. However, the project suffered considerable 

delay and political opposition to electrification and did not 

become operational during the assessment period. Partial 

funding was committed by private equity funds for another 

proposed merchant line between upstate New York and New 

York City (Conjunction LLC’s 2,300-MW Empire Connection). 

In California, while only 15 miles of transmission were built 

during the assessment period, a public-private partnership 

raised equity and debt financing to upgrade the Path 15 

bottleneck in central California and two projects were initiated near San Diego. 

Based in part on the need for clear incentives for transmission investment, FERC provided return on equity and 
S T A T E O F T H E M A R K E T S

73

structural incentives for the creation of independent transmission. Two integrated utilities in Michigan, DTE Energy 

and Consumers,138 sold their transmission assets to create 

such entities and one in Wisconsin, American Transmission 

Co., while not independently owned, is now operated as a 

stand-alone transmission company. While there has been 

limited independent operating history for these companies, 

each has increased proposals and expenditures for new 

projects, both within and outside their regulated footprints. 

Structural and financial impediments explain much 

of the relatively low investment level. It remains easier and 

quicker to site, license and construct new power plants and 

gas transmission pipelines than electric transmission lines. 

The primary factor making siting gas transmission pipelines 

easier than siting electric lines is regulatory bifurcation. In 

order to commit funds for transmission investment, developers generally require confidence regarding cost recovery, 

either through regulated regimes or in the merchant context 

through sustained price signals, visibility of revenues and 

costs, reasonable certainty of project completion based 

on obtaining rights-of-way, environmental and regulatory 

approvals and the ability to obtain equity and debt financing. 

Clear market price signals for new transmission do 

not exist in regions lacking LMP. In markets with LMP, 

price signals are insufficiently long term. While TLRs are 

responses to congestion and may signal repeated congestion at identified flowgates in regions without organized 

markets, curtailments are not ranked on economic merit, 

thus providing no price signals or revenue sources for 

new transmission investment. In organized markets, LMP 

signals exist and can be captured financially through FTRs. 

However, LMPs vary over time and are difficult to lock in as 

a long-term revenue source.139

During the assessment period, market participants had 

limited tools to forecast projected transmission revenues. 

For merchant facilities, available instruments did not provide 

long-term revenue certainty. TLRs are not financial instruments and FTRs were available only as seasonal or annual 

instruments and would need to be longer term to support 

financing. For the regulated additions that represent the 

majority of transmission investment, revenue certainty is 

assured only after siting, licensing and regulatory approvals. 

Siting difficulties caused by environmental and community 

concerns are compounded by the multiple jurisdictions 

through which transmission lines often pass. While there 

is federal siting authority for natural gas pipelines, the lack 

of such authority for electric transmission has compounded 

difficulties in coordination and obtaining approvals from 

multiple jurisdictions. Measuring benefits and allocating 

costs between beneficiaries and end-use customers that vary 

over time presented difficulties for merchant and regulated 

projects alike. For the integrated utilities, which own the 

majority of the transmission system, new lines were added 

to the rate base and are paid for by end-use customers in 

the service territory where the lines were built. Mechanisms 

to better align benefits and costs so that regional generation 

and load outside of the service territory pay for benefits 

of congestion relief and reliability are being addressed by 

regional planning processes such as ISO-NE’s Regional 

Transmission Expansion Process. 

Incumbent utilities with the financial ability to invest 

must allocate capital to transmission projects, but can have 

powerful disincentives to doing so. Because of regulatory 

lag on existing rate base, a utility can increase earnings 

by spending less on operations and maintenance than 

provided for in their tariffs which are based on historical 

cost-of-service. In the absence of mandatory reliability 

standards, there may be little prospect for financial penalty 

to the utility for any adverse reliability effects of the lower 

spending. During the assessment period, utility management 

found more compelling uses for capital, based on higher 

return expectations (as was the case for generation when 

investment decisions that affected expenditures in the 

assessment period were made), though as generation returns 

have not met expectations, this is changing. Incentives exist 

for integrated companies not to invest in transmission that 

will relieve congestion to load pockets where they also own 

generation. In addition, in regions with partial or initial RTO 

and ISO formation, uncertainty over ultimate control and 

ownership made investment less attractive. 

Transmission investments are long-lived and the lack 

of adequate and sustained energy price signals that can be 

contracted upon, made more difficult by declining liquidity 

in forward markets for power, increased the difficulty of 

making merchant investment decisions and financing plans 

once made. If built outside of the rate base, transmission lines 

generate cash flows based on market price differentials for 

energy at both ends and these cash flows are more difficult 

to project than those for generation. Difficulties raising debt 

financing for market-based transmission projects may have 

been compounded by financial markets tarring merchant 

transmission lines with the brush of merchant generation. 

138 Docket Nos. ER02-23-000 and EC03-95-000. 139 New transmission construction is particularly susceptible to diminishing its 

own value by relieving the very congestion that led to the price differences 

it arbitrages. While an issue confronted by other capital investment with 

scale economies, it is particularly acute for transmission in part because of 

the relative size of the market it addresses and because participants have 

found it difficult to capture the arbitrage value suggested by LMP up front 

by entering contracts before building.
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74

General Investment Conditions

In general, the financial conditions of market participants 

impeded the ability and willingness to initiate significant 

levels of new infrastructure investments during the assessment period. While significant levels of new investment in 

generation did occur during the assessment period, it had 

been planned and financed during the boom preceding the 

period when signals and capital were present. Ten of the most 

active of these companies, which include energy merchants 

and convergence companies, spent $28.5 billion to finance 

construction of 60 GW, or roughly 42 percent of new capacity 

installed from 1998 through 2002, and were rewarded with 

growing equity markets until the market dropped in 2001.140

In contrast to periods before deregulation of wholesale power 

markets, investors and lenders and not end-use customers 

bore a significant portion of underperforming investments 

made in deregulated generation assets.

Merchants, convergence companies and traditional 

utilities borrowed heavily to fund investments in new generation, as well as fund acquisition of existing generation and 

establish power marketing and trading arms, increasing 

reliance on debt as a portion of their capital structures. Total 

debt for the 40 largest power and utility companies,141 which 

had been below $150 billion from the 1980s through the end 

of 1996, rose to $200 billion by the end of 1998 and peaked 

at above $367 billion in March 2002. Overall debt levels 

remained at roughly $350 billion in 2002 and 2003, but debt 

composition changed with continued borrowing by certain 

participants, debt retirement by others, negotiated maturity 

extensions and debt defaults. Debt to total capital rose from 

54 percent for the 40 largest companies at the end of 1996, 

to a high of 67 percent at the end of 2001 and remained at 

approximately 66 percent through June 30, 2003 (figures 

that would be higher if they reflected off-balance sheet 

financings for project financed projects). 

The large infusion of new generation in many regional 

markets contributed to low and declining energy prices 

during the review period. At the same time, generators 

were squeezed by the increasing costs of natural gas. Prices 

both signaled less need for new investments and lowered 

the financial ability for some participants to fund that 

infrastructure. In the organized markets where capacity 

markets existed, excess capacity decreased prices. As a 

significant proportion of new generation was gas fired, lower 

spark spreads hurt operating margins for many merchants, 

lowering equity returns and/or threatening debt service. In 

some regions, bid mitigation negatively affected earnings. 

Low operating revenues coupled with heavy debt 

burden incurred to finance construction and acquisitions 

threatened the financial condition of most merchant and 

convergence companies, leading to credit deterioration, 

project cancellations, exits or cutbacks from trading and 

marketing by some, and the bankruptcies of others. In 

general, regulated utilities without large affiliated merchant 

activities still retained relatively strong finances and 

remained able to make additional investments. As shown in 

Figure 41, credit deterioration was marked in the assessment 

period, continuing the trend established in 2001. At the 

beginning of 2002, of the 313 utility holding companies and 

operating subsidiaries rated by Standard & Poor’s, 49 percent 

were rated A or better, 45 percent in the BBB category and 

6 percent below investment grade. By year end, 3 percent 

were rated A or better, 46 percent were BBB rated and 

8 percent were non-investment grade (BB+ and lower). 

During the period, 182 ratings were downgraded, while 15 

were upgraded. In the first half of 2003 the trend continued, 

though its pace slowed somewhat as 83 ratings were downgraded and 8 upgraded. Non-investment grade companies 

were downgraded to even more speculative grades.142

Merchants and utility holding companies with significant 

exposure to merchant activities experienced the largest 

credit deterioration and it affected their business operations 

most significantly.

Utility divestiture of generation, ISO and RTO formation and enhanced competition progressed to a greater 

degree in certain regions of the country than in others, 

with more generation sold or transferred in the ISO-NE, 

NYISO, Midwest, ERCOT and CAISO than in the Southeast, 

the Southwest and the Northwest. Partially because of the 

plight of the merchant generators and traders, deteriorated 

credit and equity conditions were more prevalent in regions 

with operating or forming regional markets. The market 

structures in the regions without organized markets did not 

experience that level of restructuring. A large majority of the 

investment made in these regions was by federal or municipal entities or integrated utilities operating under regulated, 

cost-based models without prevalent credit and equity issues. 

However, in certain regions, there was an attempt by unregulated players to make inroads and in the Southwest region, 

Entergy and Southern subregions of the Southeast, and 

to a lesser extent in the Northwest, significant generation 

was built by merchants (much of which did not perform to 

140 Deutsche Bank Securities, Factset: Includes AES, Aquila, Calpine, Dynegy, El 

Paso, Edison Mission Energy, Mirant, NRG, Reliant Resources and Williams. 

The market capitalization of these 10 companies grew from $49.4 billion at 

year-end 1998 to $172.3 billion at year-end 2000. 141 Factset: Includes Ameren, AEP, AES, Aquila, Allegheny Energy, Constellation, 

Cinergy, CMS Energy, Calpine, Dominion Resources, DPL, DTE Energy, Duke 

Energy, Energy East, Enron, Entergy Corp., ComEd, Edison International, 

Exelon, FirstEnergy, FPL Energy, GPU, Mirant, Niagara Mohawk, NRG Energy, 

Northeast Utilities, Orion Power, PG&E Corp., PSE&G Corp., Progress Energy, 

Pinnacle West, PPL, Centerpoint Energy, Reliant Resources, Scana, Southern 

Co., TECO Energy, TXU Energy, Wisconsin Energy and Xcel. 142 Standard & Poor’s, Utilities and Perspectives, June 26, 2003, and previous. 

Includes utilities with both electric and gas operations.
S T A T E O F T H E M A R K E T S

75

expectations). In regions with organized markets, the lowest 

ownership of capacity by non-investment grade companies 

was 22 percent in PJM and the highest was in ERCOT, with 

48 percent. Of the regions without organized markets, by 

contrast, only in the AZ-NM-SNV subregion of the Southwest 

was more than 10 percent of the capacity owned or energy 

produced by non-investment grade entities.143

From January 2002 until June 2003, merchant and 

convergence (companies with operations spanning power 

and gas trading, marketing, transmission and generation) 

sector market capitalization declined from $77.4 billion to 

$19.0 billion and two merchants, NRG Energy and National 

Energy Group, declared bankruptcy. Enron was already 

operating under bankruptcy. Other merchant and convergence 

companies restructured their balance sheets, attempted to 

sell assets, cancelled announced projects, cut back or exited 

energy trading and sought new sources of capital. Increased 

risk perceptions by investors in the sector and increased 

segmentation of the risks of particular participants led to 

increased capital costs for many. Amid declining credit 

ratings and stock prices, companies sought to raise cash 

needed to finish construction of partially completed plants, 

support remaining trading activities and extend or repay debt 

maturities. Where possible, participants provided collateral 

in performing assets to obtain new loans or extensions. 

Regulated utilities outperformed the merchant sector in equity 

markets in regions both with and without organized markets.

New sources of capital emerged and the sector 

attempted to limit the need for new capital. While traditional 

retail and institutional equity and fixed-income investors 

lost or took money out of the sector, high yield fund 

investors, private equity funds and hedge funds emerged 

as new sources of capital. The sector also attempted to 

limit the need for new access to capital by selling assets, 

restructuring or turning over assets to lenders. Lenders in 

many cases showed a willingness to extend maturities or not 

enforce lending covenants for troubled plants and waited 

for improved market conditions. Sales of underperforming 

assets to new entrants and stronger players occurred less 

often than many expected. More prevalent were sales of 

performing assets by troubled merchant corporations to 

provide liquidity and pay down debt.144 The paucity of deals 

for troubled assets was due partly to divergent price expectations of buyers and sellers and because sellers sought to 

sell assets without long-term contracts while buyers desired 

contracts. The large number of plants for sale gave those 

who valued new capacity the option to purchase rather than 

build that capacity, which was in most cases a quicker and 

cheaper option.

Lower credit ratings had implications not only for 

capital costs but also for the liquidity and collateral 

requirements for trading and marketing in the futures and 

physical power and gas markets. Heightened collateral 

requirements and changes in how rating agencies assess the 

risk of power trading led to higher explicit or implicit equity 

support needs for these activities. This ultimately resulted 

in reduced electricity and natural gas trading and the exit 

143 Standard & Poor’s, Utilities and Perspectives, June 26, 2003 and previous. 

Platts POWERdat, August 2003. 144 Citigroup Smith Barney, Ray Niles, May 8, 2003. From Jan. 1, 2002 through 

May 1, 2003, 7,200 MW were sold for $3.5 billion in 17 transactions

Figure 41: Energy company credit ratings deteriorate before and during the assessment period.

Source: based on Standard & Poor’s data from Bloomberg L.P. Graphic and analysis by OMOI.
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

76

of several participants.145 While liquidity declined, financial 

players, including investment and commercial banks and 

hedge funds, entered, returned to or strengthened trading 

activities to take advantage of the void left by the exit of 

many participants.

Summary of Electricity 

Market Performance

Based on the analysis detailed above, we conclude 

that electric markets performed with varying success, but 

with greater effectiveness and transparency in those regions 

with markets operated by ISOs or RTOs. Progress was made 

during the assessment period in market design and market 

operation. Nevertheless, there remained regions of the 

country where the basic conditions and market structure 

to support efficient market performance were not in place. 

OMOI will continue to monitor progress in the future on 

issues of associated market development, risk management, 

transparency and access by independent generators to 

regions without organized markets.

145 Standard & Poor’s, Standard & Poor’s Introduces New Price Assumptions 

for Merchant Power Exposure, Oct. 30, 2003. Companies announcing scaling back or exiting from power trading in press releases from November 

2002 though March 2003 included: Allegheny Energy, Ameren Corp., 

AEP, Aquila, Calpine, CenterPoint Energy, Cleco, CMS Services Marketing 

& Trading, Duke Energy, Dynegy Marketing and Trade, El Paso Merchant 

Energy, Enron, E Prime, IdaCorp, Mirant, National Energy Group, NRG 

Energy, Reliant Resources, Tractebel North America, UBS Warburg Energy 

and Williams. 
S T A T E O F T H E M A R K E T S

77

T

he North American natural gas market is an integrated system of regional markets of production and consumption, connected by an extensive pipeline network and related infrastructure. 

Physical and financial transactions involve multiple venues, pricing methods, delivery periods 

and delivery points. 

Reported natural gas prices during the assessment 

period generally behaved consistently with the forces of 

supply and demand. The market response exhibited characteristics of a well functioning market—it delivered products 

on time to customers and spurred reasonable levels of investment. Moreover, participants had multiple alternatives for 

managing risks, including price volatility. 

During the assessment period, the market did face 

challenges. Over the past two years, the natural gas market 

exhibited increases in prices, greater price volatility, supply 

tightness, severe swings in storage inventory volumes, credit 

problems, decreasing volumes of trade and price index 

credibility issues, among other factors. Market participants 

had opportunities to use storage and physical, financial and 

pipeline capacity contracts to manage risks, but liquidity for 

forward contracts declined. The exit of several major energy 

merchant companies, the decrease in the activity level of 

other companies and credit concerns reduced the liquidity 

for forward contracts. The ability of participants to hedge 

risks was limited by the decline in liquidity (as evidenced 

by the number of trades offered to the market) and the 

creditworthiness of the counterparties. This is important for 

end-users of natural gas because it influences their ability to 

manage price volatility effectively. 

NATURAL

GAS MARKET

PERFORMANCE

Because of variations in the types and locations of 

natural gas transactions, the quality of information about 

the formation of prices varied. The Henry Hub in Louisiana 

remained a highly liquid physical market and was the 

benchmark for many derivative financial products; it was 

the most transparent point for price formation during 

the assessment period. In markets that offer limited 

transparency to market participants and those not involved 

in transactions, price discovery was frequently based on 

commercially developed indices assembled through surveys 

of market participants who agree to report and indices 

developed on the basis of exchange-conducted transactions. 

During the assessment period, the adequacy and reliability of 

price information became an ongoing concern that both the 

Commission and industry are addressing. 

This section explores five aspects of natural gas market 

performance. They include:

 Market Structure

 Prices and Locational Basis

 Risk Management

 Transparency

 Investment 
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

78

Market Structure

Critical physical characteristics of natural gas determine 

in large part the structure of the natural gas market. The 

first is that natural gas is found in geologic basins, which 

are concentrated in selected locations in the United States 

and the world. Second, natural gas producing basins are 

typically far from consuming centers. Finally, natural gas 

must be enclosed in a vessel, typically a pipeline, to be 

shipped. The result is that, when used as a fuel, natural gas 

requires a complex and relatively inflexible infrastructure 

to gather the gas from the production fields and deliver it to 

customers. The physical characteristics of natural gas and the 

requirements that they impose on the supply system drive 

the structure of the market, as is illustrated in Figure 42.

Upstream, natural gas production is a competitive 

industry. More than 6,800 companies, including 21 large 

integrated firms, produce natural gas in the United States. 

In addition, imports from Canada provide approximately 

17 percent of U.S. consumption, and liquefied natural gas 

(LNG), imported from offshore sources, provides less than 1 

percent of the nation’s natural gas supplies. 

Natural gas typically travels from the production site 

through gathering pipes to processing facilities. With some 

exceptions these facilities are competitive and not regulated. 

Shippers (or their agents) can purchase gas at either 

upstream receipt points or downstream delivery points 

(often a market center or hub). A hub or market center can 

provide customers with access to two or more pipeline 

systems, transportation between these points, metering 

and administrative services to facilitate the associated 

transactions and in some cases storage, balancing, parking 

and loaning of gas. The most important hub in the United 

States is the Henry Hub, located at Henry, Louisiana. Henry 

Hub connects 14 gas pipeline systems, is a successful cash 

trading marketplace and is the delivery point for the Nymex 

natural gas futures contract.

From the upstream facilities, most natural gas moves 

to customers on the interstate pipeline system, a system 

of over 180,000 miles of large diameter, high-pressure 

pipelines. Because of economies of scale and scope 

and barriers to entry, interstate natural gas pipelines 

are natural monopolies, regulated by the Commission. 

Pipelines operate as contract carriers, offering a variety of 

Figure 42: Regional North American natural gas markets are connected by pipeline and related infrastructure.

Note: “DEFS” is Duke Energy Field Services Co. “EPGT” is EPGT Texas Pipeline Co.

Source: EIA, GasTran Gas Transportation Information System, Natural Gas Market Hubs Database, as of August 2003.
S T A T E O F T H E M A R K E T S

79

Figure 43: Monthly natural gas prices peak in late-winter 2002 and remain high through following summer.

firm and interruptible transportation services, storage and 

gas custody management services. 

As the gas moves between producing and consuming 

centers, it is often placed in storage. Storage fills the gap 

created by seasonal variations in gas demand. In winter, 

demand exceeds the amount of gas coming out of the 

ground, and in summer, production exceeds demand. As 

of the end of 2002, working gas storage capacity in the U.S. 

lower-48 states was estimated at 3.3–4.0 Tcf.146 Regionally, 

approximately one-quarter of storage capacity is located in 

producing regions and three-quarters is located in consuming regions.147

The integrated physical infrastructure provides 

a flexible system, enabling customers to buy natural 

gas from numerous producers, marketers and local 

distribution companies (LDCs). For example, customers 

can acquire natural gas upstream or deliveries at downstream locations and rely upon natural gas marketers to 

purchase, contract for transportation and storage, deliver 

and handle the financing of their gas. Wholesale marketers manage supply chain activities on behalf of their 

customers using their knowledge of regional markets, 

physical or financial markets, enhancement of the value 

of physical assets or price and credit risk. The typical gas 

customer—especially the residential customer—has gas 

delivered by one of the 1,294 LDCs in the United States,148

which take title to the natural gas when it enters the 

pipeline, transport it to their own distribution systems, 

and resell it to customers. The LDCs, with some exceptions, are typically the “retail” marketers.

Regulation of the natural gas supply chain seeks to 

allow competitive forces to prevail where they exist and to 

affect only those portions of the system where participants 

have the potential to wield market power. The Commission 

does not regulate the market price of natural gas commodity bought or sold along a pipeline. The Commission 

does regulate the interstate pipelines with the objective 

of assuring that customers have access to competitive gas 

supply opportunities. Commission regulations establish 

open access conditions and maximum tariffs for transportation. Most gas storage facilities are owned by pipeline 

companies or LDCs and therefore are regulated, either by 

the Commission or by the states. States also regulate (as 

appropriate) gathering, intrastate pipelines and natural gas 

sales by LDCs to end-use customers.

Note: For the assessment period, Gas Daily and ICE next-day physical prices at Henry Hub averaged within $0.01/MMBtu of each other. 

Source: Platts Gas Daily and ICE. Analysis and graphic by OMOI.

146 EIA, “Natural Gas Storage,” presented by William Trapmann at North 

American Gas Strategies Conference, Oct. 29, 2002. Storage capacity 

estimates vary due to assumptions, methodology and survey organization, 

among other factors. 147 EIA spreadsheet, U.S. Total Natural Gas Storage Capacity by State, last 

updated on 7/22/03. Data are through 2001. Excel file name: ng_stor_cap_

sac_a_s.xls. Regional working gas storage capacity estimates are based on 

state ratios of total gas storage capacity. 148 American Gas Association, www.aga.org, Stats & Studies, State Profiles.
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

80

Prices and Locational Basis

Prices

Natural gas prices reached new levels in the assessment 

period. As shown in Figure 43, prices were relatively low 

in early 2002 but began rising in spring 2002 and escalated 

rapidly in early-2003 as the weather turned more severe, and 

increased consumption stressed the natural gas supply chain.

From the start of January 2002 through mid-January 

2003, the daily Henry Hub price increased over 100 percent, 

or $3/MMBtu. By late-February, 2003 daily citygate prices 

spiked as high as $40/MMBtu in New York, reflecting severe 

weather and well freeze-offs.149 At Henry Hub, February 2003 

prices spiked to near $19/MMBtu. After a decline in Henry 

Hub prices through March and early April 2003 to $4.86/

MMBtu, prices rose again to $6.26/MMBtu in early June 

2003. Prices ended the assessment period at $5.18/MMBtu.

The significance of the upturn in natural gas prices 

was reflected in the new peaks in both spot and forward 

market prices for Henry Hub and forward indices. Forward 

markets exhibited a significant upward shift in average price 

as compared to the 1990s, as shown in Figure 44. From 

June 1990 through December 1999, the average price for 

next month futures was $2.04/MMBtu. From January 2000 

through October 2003, the average next-month futures price 

more than doubled, to $4.18/MMBtu. 

Consumption

Customers responded to the higher prices as appropriate in an efficient market. Estimates indicate consumption 

of natural gas for the first half of 2003 was lower than in 

the first half of 2002. Two sectors, industrial and power 

generation, reduced natural gas use in the wake of higher 

prices, while residential customers and commercial facilities 

increased their consumption largely in response to colder 

weather, as shown in Figure 45. 

The most significant change was in power generation. 

Monthly generation trends for electric power producers by 

source are highlighted in Appendix 5. After increasing 6.2 

percent between 2001 and 2002, natural gas use in power 

generation declined 13.0 percent in the first six months 

of 2003 relative to the same period in 2002. Key factors 

accounting for the decline include: 

 fuel switching from natural gas to oil, 

 improved hydroelectric availability in the West, and 

 replacement of less efficient natural gas units with 

gas combined-cycle plants that can generate the same 

amount of electricity with about 30 percent less fuel.150

Industrial users continued to reduce their natural gas use, 

which fell from 20.2 Bcfd to 19.7 Bcfd (2.2 percent between 

Figure 44: Natural gas futures prices reach new levels.

Source: Nymex data from Bloomberg L.P. Analysis and graphic by OMOI.

149 FERC Staff, Report on the Natural Gas Price Spike of February 2003, presented to the Commission on July 23, 2003. 150 The heat rate on a state-of-the-art gas combined-cycle plant is usually 7,000 

Btu/kWh or lower, whereas older steam gas plants may have heat rates in 

excess of 10,000 Btu/kWh. 
S T A T E O F T H E M A R K E T S

81

2001 and 2002). Industrial sector gas consumption declined 

another 5.6 percent in the first half of 2003 relative to the 

same period in 2002. Since 2000, industrial production levels 

represented by a composite index of six key energy-intensive 

industries accounting for as much as 70 percent of overall 

industrial gas demand—food; petroleum; paper products; 

stone, clay and glass; chemicals and primary metals—have 

declined by over 6 percent.151 Some energy-intensive industries 

have retrenched more than others. Increases in natural gas 

prices have had pronounced influence on the commercial 

operations of the chemical and aluminum industries. 

During the assessment period, eight U.S. manufacturers 

of nitrogen fertilizer closed their plants permanently.152

Numerous aluminum facilities are currently idled, and the 

United States may have become the marginal supplier of 

aluminum production internationally.153 Many U.S. chemical 

manufacturers now have a comparative cost disadvantage 

because foreign feedstock (naphtha) prices are lower.154

The commercial and residential sectors demonstrated 

substantial increases in consumption over the assessment 

period, indicating the effect of severe winter weather in 

2003. Despite a warm winter, residential customers increased 

natural gas consumption 2.8 percent from 2001 to 2002; in 

the much colder first half of 2003, residential natural gas 

consumption soared, rising more than 10 percent relative to 

the first half of 2002. Commercial customers also demonstrated strong demand for natural gas, with a 4.2 percent 

increase in consumption in 2002 relative to 2001 and an 

increase of 4.6 percent in the first half of 2003 relative to the 

earlier year.155

Supply

Tight supplies were a major factor in the increase in 

natural gas prices. According to the EIA, domestic production fell 3.2 percent in 2002, which was consistent with a 

26 percent drop in the rig count during the same period.156

For 2003, EIA estimates that production increased, but 

other analysts disagree, arguing that production fell.157

Resolution of these divergent estimates is not possible at 

Figure 45: Overall consumption declines in first half of 2003, but residential and commercial demand increases.

Note: Natural gas consumption by vehicles represents less than 1 percent and is not shown.

Source: EIA data compiled from EIA forms 759, 857 and 895. Analysis and graphic by OMOI.

151 Energy Ventures Analysis, Inc., Outlook for Natural Gas Demand for Winter 

2003–2004. 152 General Accounting Office, Natural Gas: Domestic Nitrogen Fertilizer 

Production Depends on Natural Gas Availability and Price, GAO-03-1148. 

September 2003. 153 Nearly 200 MMcfd of Pacific Northwest gas demand related to aluminum 

smelting may be permanently lost. CERA, “The Demand Wild Card: Pacific 

Northwest Aluminum,” July 2003. 154 The Federal Reserve Board, The Beige Book, Oct. 15, 2003. 155 OMOI analysis of EIA data compiled from forms 759, 857 and 895; available through EIA’s Natural Gas Navigator, http://tonto.eia.doe.gov/dnav/ng/

ng_cons_sum_nus_m_d.htm. 156 EIA data, available through EIA’s Natural Gas Navigator, Natural Gas 

Marketed Production, http://tonto.eia.doe.gov/dnav/ng ng_enp_sum_vgm_

a_s.xls. (last updated on 7/22/03); and Baker Hughes, Inc. natural gas rig 

data, website: www.bakerhughes.com, spreadsheet: U.S. Rotary Rig Count. 157 Lehman Brothers Equity Research, U.S. Energy and Power, Oil & Gas: E&P 

(Large Cap) Industry Update, Oct. 31, 2003. Thomas R. Driscoll is the analyst.
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

82

this time. If an increase occurred, it did not overcome the 

loss of deliverability in 2002, relative to 2001, with the 

resulting effect that markets are tight. Other supply stresses 

during this period included reduced Canadian imports and 

increased exports to Mexico. 

As gas prices increased in 2002, producers 

responded with additional drilling in an appropriate 

response to price signals. Nevertheless, drilling did not 

immediately relieve supply tightness, because of the time 

required to bring new gas production and discoveries to 

market and also the accelerating decline rate for existing 

production, as illustrated in Figure 46. 

Figure 47 illustrates how tight supplies, combined with 

strong winter demand, resulted in a gap that put upward 

pressure on prices. The gap appears to be larger in February 

2003, the month when a natural gas price spike occurred, 

than it was in February 2002 or any other time in the assessment period. Generally the supplies that fill this gap include 

a variety of LDC peak shaving resources, pipeline and utility 

linepack options that are not measured in the available 

statistics. Other explanations include inaccuracies in documenting volumes moving in and out of storage and lags and 

mismatches in time periods among data sources.

Figure 46: Decline rates increase.

Note: Decline rate of base gas production if no new wells had been drilled, and equivalent production loss.

Source: NPC, Balancing Natural Gas Policy, September 2003.

Figure 47: Production versus storage withdrawal gap widens in February 2003.

Source: EIA consumption, storage, supply and import/export data from EIA; some supply data provided to EIA by the U.S. Mineral Management 

Service; import/export data from DOE’s “Quarterly Natural Gas Import and Export Sales and Price Report.” Analysis and graphic by OMOI.
S T A T E O F T H E M A R K E T S

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Source: EIA. Analysis and graphic by OMOI.

Storage

Tight storage conditions also influenced prices. Figure 

48 shows that lower-than-average storage levels are associated with higher prices.

As shown in Figure 49, over the 18-month assessment 

period, storage conditions shifted from abundant, reaching 

five-year highs and the upper levels of capacity in April 2002, 

to tight, reaching five-year lows in April 2003. The April 

2002 storage levels were the result of a warmer-than-normal 

winter during 2001–2002 that reduced natural gas use. 

Robust injections through the summer and fall translated 

into five-year high storage levels at by the beginning of the 

heating season on Nov. 1, 2002. However, an unusual cold 

snap in late-November and early-December prompted 

above-average storage withdrawals early in the season. 

Continuing cold weather in January and February severely 

reduced working natural gas storage levels. As a result, 

working natural gas in storage began the 2003 injection 

season at a five-year low level of 623 Bcf, or 15 percent below 

the prior low in terms of total supply. As the fill season 

continued, weekly injections often set records, despite the 

higher costs of natural gas to fill storage. 

From February into summer 2003, uncertainties about 

whether storage could recover from the steep drawdown 

helped to support higher natural gas prices. Faced with 

record low storage levels and the potential for increased 

natural gas use for power generation if the summer were 

unseasonably warm, storage users continued to buy and 

inject gas into storage, despite the record prices. 

Figure 49: Storage use pushes upper and lower capacity limits.

Note: Figure includes 199 data points, for the weeks ending 12/31/99–10/31/03.

Source: EIA. Weekly average of Platts Gas Daily spot price data. Analysis and graphic by OMOI.

Figure 48: Relationship strong between storage level and price.
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Source: Platts Gas Daily, Pipeline Tariffs. Analysis and graphic by OMOI.

Locational Basis

Regional price differences, signals that additional 

pipeline capacity may be needed when they exceed tariffs by 

a sufficient amount and for a sufficient amount of time, have 

been moderate in most regions. For this report, we will refer 

to the difference between a natural gas price at a market hub, 

citygate or supply receipt area and a reference point, most 

often Henry Hub, as “basis” or “locational basis differential.”158

During periods of low pipeline capacity utilization, 

the basis differential will reflect the variable costs of 

transportation and typically be below the 100 percent load 

factor pipeline tariff rate in an efficient natural gas market. 

As capacity tightens, the basis differential will reflect regional 

supply and demand conditions in a market and, depending 

on the severity of the constraint, the basis may exceed the 

cost-based tariff rate for transmission capacity. Consistently 

and sufficiently high basis differentials signal continued 

constraints and the need for new pipeline capacity.

Functionally meaningful basis relationships are 

consistent with physical gas flows. For example, there is a key 

relationship between gas sold or bought in Zone 3 (Station 65) 

on Transcontinental Gas Pipe Line (Transco) and deliveries 

into New York City from Transco Zone 6. Because the basis 

between the two reflects the market’s view of the difference in 

value of natural gas between the two points, a price increase 

in Zone 3 of 15 cents typically leads to a price increase of equal 

or greater value at Transco Zone 6-NY. During the period 

of this report, the basis between those points was as little as 

19 cents, but three times during January and February 2003 

the basis was more than $10.159 Basis values were equal to or 

below tariff rates for most of assessment period, indicating that 

pipeline capacity was generally adequate. 

Figure 50 demonstrates the seasonal and 

market-sensitive nature of pipeline capacity values as 

imputed from the bundled natural gas markets on a 

monthly basis. It shows the basis differential, less the tariff 

rate, plus fuel for several transmission corridors from the 

East to the West. As shown, basis values have been equal to 

or below tariff rates for most of the period in study, indicating generally sufficient capacity. 

Higher basis differentials occurred in the Rocky 

Mountain region, especially prior to the Kern River 2003 

Expansion Project, the San Juan Basin and occasionally in 

the Northeast. The Opal to Southern California (SoCal) 

differential indicated a need for capacity from the Rockies to 

California beginning in mid-2002. The addition of the Kern 

River Gas Transmission expansion during the assessment 

period increased capacity from 845 MMcfd to 1,731 MMcfd 

on May 1, 2003. Since that time, transient flow conditions 

have allowed flow to be more than 1,900 MMcfd, and the 

pipeline has been fully contracted at design capacity. The 

basis valuations shown in Figure 51 demonstrate the market 

response to the capacity addition, with the basis differential 

immediately narrowing to levels consistent with the Kern 

River tariff for firm transportation.

Figure 50: Pipeline capacity generally adequate for much of the year.

158 Basis differential is used as an indicator of the value of additional 

transportation capacity and is based on the difference in value between the 

wholesale delivery destination and a benchmarked origin. 159 The basis differential calculations are based on daily indices. In the case of 

Transco Zone 6-NY, the index is based on a smaller volume of transactions 

than the index for more liquid points. 
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Note: Transco Zone 6 Zone 6-NY and Zone 6-non-NY basis differentials to Henry Hub versus maximum tariff rates plus fuel; lightly shaded bands 

denote a five-month winter period (November–March).

Sources: Platts Gas Daily, Pipeline Tariffs. Analysis and graphic by OMOI.

In the Northeast, the basis, although volatile in the 

winter, did not exceed tariff rates for extended periods 

of time. For instance, Transco Zone 6 is a market center 

covering a six-state area from Virginia to New York City and 

is characterized by volatility and limited pipeline capacity, 

especially into New York City. This occasionally causes a 

large disconnect between transactions of natural gas bound 

for New York City and natural gas that is destined elsewhere 

in the Northeast. Historically, in off-peak periods, the basis 

differentials are normally below the tariff rates. Sometimes, 

however, basis differentials from the Gulf Coast to Transco 

Zone 6-NY and Zone 6-non-NY, have exceeded the Transco 

tariff for relatively brief periods during the winter, with the 

value significantly higher than the regulated tariff rate at 

times. Figure 52 demonstrates the Transco Zone 6-NY and 

Zone 6-non-NY basis differential to Henry Hub versus the 

tariff rate for Transco firm transportation.

Most often these high basis costs will be borne by 

generators or LDCs balancing their requirements. Many 

customers have thus far decided that it is more economic 

to pay the higher basis costs for a short period of time, 

rather than subscribe to year-round pipeline additions, 

either existing or new construction reservation, with the 

associated, annual demand charges. The reasons for not 

committing include unwillingness or inability to enter into 

long-term contracts and the use of alternative means for 

meeting supply needs. A shipper also may find that it is less 

costly to pay for gas during short periods of high prices and 

high volatility than to commit to a long-term contract. Basis 

differentials that exceed tariffs on a sustained basis indicate 

that incremental capacity may eventually be needed, but, 

with efficient pricing signals, the capacity is unlikely to be 

built until the benefits exceed the costs. The role of basis 

differentials in analyzing the need for new pipeline construction is discussed in a later Investment subsection.

Figure 51: New infrastructure affects Rocky Mountain basis differentials.

Source: Platts Gas Daily, Pipeline Tariffs. Analysis and graphic by OMOI.

Figure 52: Many customers choose to weather short basis blowouts rather than pay for pipeline additions.
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Risk Management

Price risk management offers the option of reduced 

exposure to price volatility, allowing predictable prices. 

Given the price volatility in the natural gas market, 

instruments to hedge price risk can offer value to market 

participants.160 Price risk management does not guarantee 

the lowest price possible for the end-user, but it does 

stabilize the price. Methods to reduce exposure to changing 

prices include storage, long-term fixed price physical 

contracts, firm pipeline capacity and financial contracts. 

During the assessment period, both the price level and 

price volatility were higher on average than in the period 

going back to the early 1990s. In addition to the absolute 

price level increase in 2002 through 2003, the volatility 

for next-day physical prices at Henry Hub rose during the 

assessment period. Figure 53 shows the historical volatility 

for next-day physical prices along with the next-day prices 

at Henry Hub from January 1991 through June 2003. The 

historical volatility is the annualized standard deviation of 

price changes that actually occurred in the market. Volatility 

is not a measure of the absolute price level, but a measure 

of the variation in price, both up and down. Price volatility 

is important to both natural gas end-users and producers 

because it signifies the range of possible price outcomes.

From the beginning of 2002 through June 2003, day-today physical price volatility at Henry Hub increased to the 70 

percent level.161 The average Henry Hub price for the same 

period was $4.22/MMBtu. During the 1991 through 1999 

time period, the next-day physical price volatility at Henry 

Hub averaged in the mid-50 percent range and the average 

price was $2.08/MMBtu. A similar move up in price volatility 

was evident in the next-month futures prices for 2002–03 as 

compared to the 1990s. The primary exception between the 

next-day physical and next-month futures historical volatility 

was during February 2003, when physical prices saw greater 

daily changes than did next-month futures prices. The 

reason for this difference is that the next-day physical prices 

were responding to the immediate problems of securing 

enough supply to meet demand, while the futures prices 

were for the next month’s delivery period, where problems 

in securing supply were expected to be less severe. 

Storage

In using storage, the seasonal spread of prices during 

the summer and winter is examined to select the best 

time to purchase gas for storage. Gas injected during the 

months of April through October is withdrawn and used 

during November through March. To the extent they have 

gas stored, market participants have options to avoid higher 

cash market prices for natural gas during the winter months. 

Figure 54 shows the estimated cost of gas in storage versus 

the average cash market price during winter 2002–03, 

indicating that customers may have benefited when they 

accessed lower-priced natural gas that had been stored the 

prior injection season. In future periods, the cost of natural 

gas drawn from storage may not always be lower than the 

winter cash market price. Futures can be used to manage the 

price risk between the injection and withdrawal periods. 

160 Price risk is the exposure to the price of the underlying commodity. For 

example, end-users of natural gas are exposed to rising prices and producers of natural gas are exposed to falling prices. 161 Historical volatility was measured using the next-day Henry Hub prices 

from Gas Daily for a rolling period of 20 days from January 1991 through 

June 2003.

Figure 53: Henry Hub price volatility increases from the 1990s.

Note: Historical volatility is calculated as the standard deviation of logarithmic returns, log (pricet /pricet-1), where standard deviation 

is based on the previous 20 days. 

Source: Platts GASdat. Analysis and graphic by OMOI.
S T A T E O F T H E M A R K E T S

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Natural Gas Futures on Nymex and 

Other Financial Instruments

In addition to storage, the natural gas market has 

effective financial instruments to hedge price risk. The 

financial markets for natural gas originated in 1990 with 

the introduction of Nymex’s Henry Hub natural gas futures 

contract. Since then, the futures contract has grown in 

use. The natural gas futures contract is now second only 

to the light, sweet crude oil futures contract in terms of 

total number of energy futures contracts traded, as evident 

in Figure 56. At the same time, an OTC market developed 

for financial products such as swaps and options for price 

points across the United States and Canada. The futures and 

OTC markets serve several important functions. First, the 

markets provide for industry participants to shift their price 

risk to other parties willing to assume the risk. Second, the 

financial markets provide price discovery. Price discovery 

gives industry participants visible prices necessary to execute 

transactions and make planning decisions. Depending 

upon the platform and product, prevailing prices of certain 

financial instruments are more accessible to the public than 

bilateral transactions done directly between two participants. 

Market participants primarily used four methods of transacting with natural gas financial instruments:

 on Nymex, the futures exchange for the Henry Hub 

natural gas futures and options contract. Other Nymex 

products include a set of natural gas futures swaps and 

basis swaps at various locations,

 on ICE, an electronic exchange for OTC physical and 

financial products,162

 through a voice broker, who matches buyers and sellers 

in OTC physical and financial transactions, and

 through a direct bilateral transaction between a buyer 

and a seller.

Generally, during the 18-month assessment period, 

the Henry Hub physical price converged with the Nymex 

futures contract expiration price. Financial instruments work 

as hedges against price exposure in purchasing or selling 

natural gas if there is a relationship between the financial 

and physical price. To the extent that physical natural gas 

and next month futures prices converge, hedges for that 

month will be efficient. Figure 55 shows the relationship 

between next-day physical natural gas at Henry Hub and 

the next month futures settlement prices.163 While the two 

Figure 54: Winter 2002–03 cost of gas in storage lower than cash market prices.

Note: The cost of storage and average cash market price is based upon prices at Henry Hub and does not include transportation to other locations. 

The cost of storage does not include demand charges, injection and withdrawal fees, which vary depending upon the type of storage facility. 

Source: Platts Gas Daily Henry Hub spot price data for the assessment period; the cost of gas in storage is a volume-weighted average of weekly 

Henry Hub prices, weighted by weekly EIA injection-withdrawal estimates, for the injection season (April–October 2002). 

Analysis and graphic by OMOI.

162 ICE is an internet trading exchange for energy, precious metals, weather 

and emissions products. Energy trading on ICE began in October 2000. The 

exchange model for ICE is a many-to-many platform where both buyers and 

sellers post bids and offers. ICE does not take title to any of the products. 163 For a discussion of the effects of the February/March 2003 natural gas 

price spike on Nymex futures see Staff Investigating Team, Federal Energy 

Regulatory Commission, July 23, 2003, Report on the Natural Gas Price 

Spike of February 2003, p. 13.
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products are different in terms of when they are delivered, 

they do move together on average. The average difference 

between the two products was $0.045/MMBtu from January 

2002 through June 2003.164 As the gas futures contract nears 

expiration (on the third-to-last business day of the month 

prior to the contract month), the price of the contract and 

Henry Hub physical gas prices, especially bid week prices for 

next-month baseload, converge. In other words, if the expiration settlement price and the monthly baseload index for the 

Henry Hub are the same price, the convergence is “perfect” 

for hedging purposes.165 For 2002 through June 2003, the 

next-month physical index prices from the Gas Daily for 

Henry Hub and the monthly Nymex futures expiration price 

fell within $0.001/MMBtu of each other on average.166

As shown in Figure 56, the natural gas futures volume 

marked a record year in 2002, with volumes transacted 

on Nymex for the Henry Hub futures contract and on ICE 

for the financial swap contracts increasing. The increase 

was likely due, in part, to the demise of EnronOnline,167 as 

participants switched to other trading venues. While still 

trending upwards, the 2003 Nymex natural gas volumes 

were less than 2002 volumes. 

Figure 55: Next-day Henry Hub spot prices move in the same direction as next-month futures prices.

Source: ICE, Bloomberg, L.P. Analysis and graphic by OMOI.

Figure 56: Nymex natural gas futures volumes trend upward.

Source: Nymex. Analysis and graphic by OMOI.

164 The largest difference between the next-day physical price at Henry Hub 

and the next-month futures settlement price was $8.837/MMBtu, which 

occurred on Feb. 26, 2003. On this date, Henry Hub next-day prices rose to 

$18/MMBtu. 165 When natural gas futures are used to hedge physical transactions based on 

the monthly physical market index, the price convergence will result in the 

participant achieving the price “locked-in” from the hedge. If the futures 

and physical market prices do not converge, the participant will have either 

an unplanned gain or loss on the transaction. 166 The range of differences between the next-month physical price and the 

next-month futures expiration price was $0.06/MMBtu. 167 In January 2002, UBS Warburg acquired EnronOnline. The EnronOnline 

system was renamed under the website UBSWenergy.com. In November 

2002, UBS Warburg announced it would shut down the former 

EnronOnline system.
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Similarly, the natural gas futures contract open interest 

declined late in 2002 and through 2003, but remained 

higher than pre-2000 levels. Open interest is a sign of 

forward participation in the market. In addition to volume 

transacted, open interest for the Nymex Henry Hub futures 

is an indicator of the market’s activity level. Open interest is 

the number of open long or short position (but not the sum 

of both long and short positions) held at any particular time. 

It is the total futures position currently held open and not 

offset by another equal and opposite transaction. Similar to 

the Nymex volume, open interest grew from 1990 into 2002. 

Figure 57 shows the weekly total open interest for the Henry 

Hub futures contract. After peaking in April and May 2002, 

open interest started to decline in June 2002. As the majority 

of open interest is held by market participants with positions 

to be hedged, the decline indicates a possible reduction in 

their forward trading in 2003. 

Credit Risk

During the assessment period, some merchant energy 

companies reduced their marketing and trading activity and 

one large merchant energy company declared bankruptcy.168

As a result of the decreased number of participants in 

the market and weakened financial conditions of other 

participants, there was a rise in credit risk, or the risk of a 

change in the counterparty’s credit quality or rating. Directly 

related to this is the default risk (the risk of the counterparty 

not performing on the contract), which may have increased 

during the assessment period. 

The rise in credit risk posed several problems for the 

market, including:

 increased difficulty finding creditworthy counterparties, 

 decreased number of counterparties willing to transact 

long-term structured contracts, and 

 increased bid-ask price spreads found in executing purchases and sales, which affects price volatility.

Prior to 2002, there were no central clearinghouses 

for bilateral or OTC physical and financial transactions. 

Previously, the prevailing risk in wholesale natural gas 

purchases and sales was a change in the absolute price level 

as it affected open (or unhedged) positions such as buying 

natural gas at an indexed price. Credit risk was managed 

primarily through relying on the credit quality of the 

counterparty or setting up contract provisions to limit the 

financial exposure via margining and/or netting transaction 

exposures against one another. These types of contract 

provisions were not widely used, and there were few 

sophisticated credit management models in place to measure 

not only current credit exposure, but potential exposure. 

Another method to manage credit risk is through a 

central clearing facility, also known as a clearinghouse. By 

using a clearing service, the counterparty credit risk in bilateral transactions is transferred to the clearing organization. 

With any clearinghouse, various items need to be examined 

such as the ability of the clearinghouse to guarantee performance of the contract in times of a price spike, necessary 

requirements for members of the clearinghouse and all 

associated costs of clearing.169 For example, in buying and 

Figure 57: Nymex open-interest decline points to less forward participation.

Source: CFTC, Commitment of Traders Report. Analysis and graphic by OMOI.

168 NRG Energy, a wholly owned subsidiary of Xcel Energy, filed voluntary 

petitions for reorganization under Chapter 11 of the U.S. Bankruptcy code 

on May 14, 2003; by Dec. 5, 2003 it has successfully completed its Chapter 

11 reorganization and emerged from bankruptcy. In addition, within two 

months after the assessment period, two additional merchant energy 

companies declared bankruptcy. On July 8, 2003, PG&E’s National Energy 

Group voluntary filed in U.S Bankruptcy Court in Maryland under Chapter 

11, in default on $2.9 billion in debt. It was renamed as National Energy 

& Gas Transmission by Maryland Court, Oct. 3, 2003 as part of reorganization. Mirant sought U.S. Bankruptcy Court protection on July 14, 2003 in 

northern Texas. 169 The CCRO white paper on Credit Risk Management reviews the attributes 

of clearinghouses (see www.CCRO.org).
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selling futures contracts, Nymex acts as a central clearing 

facility and guarantees performance of the futures contracts. 

Costs include the cost of capital for funds posted for margin 

requirements, which will vary depending on the size of the 

position, any offsetting positions and the movement of the 

underlying price. 

Nymex and ICE introduced new products starting in 

spring 2002 for credit clearing.170 These products were used 

immediately by market participants. ICE began offering 

clearing services in March 2002 for natural gas, electricity 

and crude oil products. The natural gas clearing is done via 

the London Clearing House.171 Nymex launched its clearing 

service in May 2002 for standardized natural gas, electricity, 

crude oil and refined products. Late in 2002, Nymex offered 

trading and clearing for futures contracts based on OTC 

products such as basis swaps at various defined locations. 

The swaps are financially settled, whereas the Henry Hub 

futures contracts involve physical settlements. While these 

products are not different in specifications from products 

traded in the OTC market, the service allows for electronic 

trading of the products and Nymex clearing.172 The clearing 

products are offered on Nymex’s ClearPort system, which 

started in early 2003 and which had 26 natural gas products 

at the end of the assessment period. The industry use of the 

clearing products is evident through the volumes of natural 

gas cleared on Nymex and ICE. From inception through 

late-September 2003, Nymex cleared the equivalent of 11.7 

quadrillion Btu of natural gas. From inception through 

early November 2003, ICE cleared the equivalent of 20.6 

quadrillion Btu of natural gas.173

Other actions taken by the industry to promote 

credit risk management include the publication of the 

Committee of Chief Risk Officers’ (CCRO) white paper in 

fall 2002 on credit risk management, which describes best 

practices including:

 establishment of credit policies,

 measuring credit value-at-risk,

 mitigating credit risk, and 

 use of credit provisions within master agreements 

of organizations like the International Swap Dealers 

Association (ISDA) and North American Energy 

Standards Board (NAESB). 

The CCRO document discusses credit derivatives and 

multilateral clearing as means to minimize credit risk. 

170 Credit clearing is the mechanism for settling mutual claims, the result 

of which is that the risk that a company might fail to fulfill its contract is 

pooled among many companies. 171 The London Clearing House and the Nymex Clearing House are registered 

Derivatives Clearing Organizations with the CFTC. 172 Transactions not executed on Nymex which fit the ClearPort product specifications may be cleared on Nymex. The transactions are transferred to the 

Nymex Clearing House via an exchange of futures for physical (EFP) or an 

exchange of futures for swaps (EFS). 173 ICE and Nymex press releases. To better compare cleared volumes, totals 

include volumes cleared outside the assessment period. 

Figure 58: Henry Hub volumes reported to index publishers decline in mid-2002.

Note: ICE data have been modified to make them comparable to Gas Daily data. Since Gas Daily volumes include both buy and sell sides of transactions and ICE volumes include only the sell side of transactions, ICE volumes were doubled.

Source: Platts Gas Daily and ICE. Analysis and graphic by OMOI.
S T A T E O F T H E M A R K E T S

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Transparency

Physical Market Price Transparency 

and Indices

Price transparency for natural gas varies by geographical 

region due to differences in liquidity in local markets. 

Transparency also varies depending on whether it is for 

a physical or financial product. Published price indices 

provide transparency for the physical price of natural gas 

and benchmarks for contract purposes. An index can be a 

survey-conducted composite price, established on the basis 

of systematically processed geographic-specific prices for 

daily or monthly contracts reported to an index provider. 

An index can also be a composite calculation, such as a 

transaction price based on and weighted by transactions on 

an exchange, such as ICE. 

Confidence in survey-conducted indices declined early 

in the assessment period due to allegations and announcements of misreporting transactions to survey providers. Early 

in the assessment period, revelations that price indices may 

have been manipulated helped to erode confidence in the 

market and in price discovery mechanisms. The industry’s 

reliance on indices and the role of indices in price transparency are keys to understanding the concern generated 

by these disclosures.174 Many contracts, both physical and 

financial, are tied to indices calculated from daily or monthly 

physical prices. In addition, indices are used to settle swaps, 

to establish pipeline cash-out figures and to benchmark LDC 

gas purchase performance. Because indices are integral to 

the way the industry does business, concerns that the indices 

might be unreliable ultimately precipitated modifications in 

the informal processes that supported index development. 

The bankruptcies and cutbacks at large merchant 

energy companies affected the number of transactions both 

reported and transacted. In late-2001, Enron Corp. declared 

bankruptcy.175 For a time following this announcement, the 

natural gas market was not affected significantly, because 

other participants stepped in to fill the void left by Enron. In 

April 2002, a wave of information on wash trading further 

unsettled market participants and caused a decline in stock 

prices for many energy merchant companies.176 Throughout 

2002, some once dominant industry participants closed 

their trading units or ceased trading speculatively; they 

shifted to trading strategies based upon assets such as 

174 In an announcement in mid-July 2003, the CFTC named 19 companies 

under investigation in matters related to price reporting; of those 19, 

seven—AEP, CMS Energy, Dynegy, Sempra Energy, Xcel, West Coast LLC and 

Williams—had already admitted that some staff had reported inaccurate 

prices. Gas Daily, July 17, 2003. 175 On Dec. 2, 2001, Enron Corp. filed for Chapter 11 bankruptcy. 176 On May 21, 2002 under FERC Docket No. PA02-2-000, Fact-Finding 

Investigation of Potential Manipulation of Electric and Natural Gas Prices, 

sellers of wholesale electricity and/or ancillary services in the WSCC were 

sent the request to respond to questions on physical and financial transactions during 2000 and 2001.

 Under FERC Docket No. PA02-2-000, Final Report on Price 

Manipulation in Western Markets, Fact-Finding Investigation of 

Potential Manipulation of Electric and Natural Gas Prices, March 2003, 

wash trades are generally defined as a prearranged pair of trades of the 

same good between the same parties, involving no economic risk and 

no net change in beneficial ownership. 

Figure 59: Transco Zone 6-NY volumes reported to index publishers decline in mid-2002.

Note: ICE data have been modified to make them comparable to Gas Daily data. Since Gas Daily volumes include both buy and sell sides of transactions and ICE volumes include only the sell side of transactions, ICE volumes were doubled.

Source: Platts Gas Daily and ICE. Analysis and graphic by OMOI.
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reasons for the eventual decrease in volume, both reported 

and transacted, are multiple:

 Fewer participants were in the market. 

 Remaining participants completed fewer transactions.

 Reporting procedures to index publications have 

changed because of misreporting, including inflated 

trading volumes.180

 The number of participants willing to report transactions to survey-based index publications declined. 

 Inflated reporting as a result of wash trades decreased. 

OMOI believes the practice of engaging in natural gas 

and electricity “wash trades” to inflate trading activity and revenue declined in response to the effect of 

storage and pipeline capacity.177 Gradually filling the void 

left by the exit of some of the merchant energy companies, 

new and existing market participants began marketing and 

trading. Some of the existing companies include marketing 

affiliates of producers and LDCs and some of the new market 

participants are financially oriented, such as hedge funds. 

The direct effect of the misreporting to index providers and the decline in market participants is seen in the 

number of transactions reported to the Gas Daily index178

for next-day physical natural gas products. The effect of the 

decline in market participants is also seen in the number of 

transactions in the same products traded on ICE. Figure 58 

and Figure 59 show the total monthly volume of next-day 

physical transactions reported to Gas Daily and transacted 

on ICE for November 2001 through June 2003.179 Figure 

58 shows the total monthly volume of next-day physical 

products for Henry Hub as an example of a supply point. 

Figure 59 shows the total monthly volume of next-day 

physical products at Transco Zone 6-NY as an example of a 

consuming market area point.

Both the Gas Daily and ICE volumes display an uptrend 

in physical next-day volumes in early-2002 after the Enron 

bankruptcy announcement, but the short-term increase 

was followed by a sharp decline in spring 2002 as shown in 

Figure 58. The initial increase was likely due to the closure 

of EnronOnline, Enron’s electronic trading platform which, 

prior to 2002, was used heavily in the market for physical 

and financial trades. With the exit of Enron, market participants executed their trades on ICE and Nymex, and used 

voice brokers and direct bilateral transactions. The likely 

Figure 60: The number of counterparties transacting next-day trades varies by location.

Source: ICE. Analysis and graphic by OMOI.

177 Company press releases and energy trade press. 178 Platts Gas Daily is one of several survey-based index providers, which 

include NGI’s Daily Gas Price Index and BTU’s Daily Gas Wire. 179 Platts Gas Daily index volumes may include both the purchase and sale 

side of a transaction; there are no data available to verify the extent to 

which this occurs. ICE volumes are representative of one side, the sales 

side, of each transaction. 180 On April 30, 2003 under FERC Docket Nos., PA03-1-000, PA03-2-000, 

PA03-3-000, PA03-4-000, PA03-5-000, PA03-6-000, PA03-7-000, PA03-8-000, 

PA03-9-000, PA03-10-000, PA03-11-000, American Electric Power Co., 

Aquila Marketing Service, Coral Energy Resources, LP, CMS Marketing 

Services & Trading, Dynegy Inc., Duke Energy Trading and Marketing 

LLC, El Paso Merchant Energy LP, Mirant Americas Energy Marketing LP, 

Reliant Resources Inc., Sempra Energy Trading Corp., and Williams Energy 

Marketing & Trading Co. were ordered to show that they corrected their 

internal processes for reporting trading data to the trade press or that they 

no longer sell natural gas at wholesale.
S T A T E O F T H E M A R K E T S

93

wash trading disclosures on companies’ stock prices 

and FERC’s investigation into Enron and the California 

energy crisis of 2000–2001. 

The decline in the 2002 next-day volumes is also 

evident in the transactions on ICE, as shown in Figure 58.181

For Transco Zone 6-NY, shown in Figure 59, the downtrend 

appears to have stopped and the volumes began to increase 

after reaching a low in April 2003. Comparison of Figure 

58 and Figure 59 shows that the number of transactions at 

Henry Hub exceeds transactions reported for Transco Zone 

6-NY. For some locations, there are a limited amount of 

transactions underlying the index price. 

The Commission and industry took action to restore 

confidence in the price formation process. Early in 2003, 

industry groups developed best practice guidelines and 

recommended codes of conduct for energy trading.182 Price 

index developers urged the industry to increase the level of 

fixed-price trading and rely less heavily on contracts indexed 

to survey prices, as well as to report trade data to ensure 

accurate indices.183 Many in industry and price index publishers also requested that the Commission take steps to support 

renewed confidence in price indices.184 

Further transparency in the physical market developed 

late in the assessment period. For the monthly price indices, 

Gas Daily and Natural Gas Intelligence started associating 

each location with a “tier” for information on the reported 

volume and number of transactions for the bidweek in June 

2003, effective for the July 2003 indices.185 Beyond listing the 

total transactions per location, in June 2003 ICE started to 

publish daily the number of counterparties and number of 

transactions at each location for transactions executed for 

the next-day physical product as well as to publish the same 

information for monthly bid week physical transactions. This 

information gives market participants the ability to examine 

liquidity factors and market trends at multiple locations. 

The number of counterparties transacting at the 

supply points varied from those at the market area points, 

as shown in Figure 60. Henry Hub had a large number 

of counterparties in comparison to other points and 

experienced a decline in 2002 coinciding with the fall in 

transacted volumes reported. The number of counterparties began to stabilize and recover slightly at Henry Hub 

and other points through 2003.

Monthly indices are often less liquid than day-ahead 

indices. For transactions reported to survey providers, the 

decision to use index-based monthly (baseload) contracts, 

instead of fixed-price contracts, affects the volume, reducing 

the pool of trades used for calculating fixed-price indices and 

limiting price transparency in the market. The limited liquidity for some monthly contracts is evident on ICE,186 where 

the month-ahead fixed-price products at Henry Hub are a 

small percentage of the total volume transacted for next-day 

products through the course of a month. From January 2002 

through June 2003, the total volume of month-ahead fixedprice products at Henry Hub averaged less than 6 percent of 

the total volume of next-day fixed-price products. However, 

the ratio of month-ahead fixed-price product volume to 

next-day fixed-price product volume is not the same for 

all pricing points. For example, at Waha (West Texas), the 

total volume of month-ahead fixed price products averaged 

approximately 100 percent of the total volume of next-day 

fixed-price products during the same period. The total 

volume that industry participants transact for month-ahead 

products using other methods—by voice brokers or through 

direct bilateral trades—is not known because there are no 

reporting requirements for natural gas physical and financial 

transactions outside of futures transactions.

Forward Price Transparency

Prices in forward months are necessary for participants 

planning hedges and making investment decisions. During 

the assessment period, forward price transparency was available through the Nymex Henry Hub futures contract. While 

physical price discovery relied on day-ahead and monthahead published indices, most forward price transparency 

was a function of financial markets. During the assessment 

period, Nymex offered trading in the Henry Hub contract 

out for six consecutive years. Forward price transparency at 

locations other than Henry Hub were available for shorter 

periods of time. 

Forward price transparency improved during the assessment period with the introduction in 2002 of financial OTC 

swaps on Nymex’s ClearPort system. Prior to this introduction, forward contracts at various locations were available via 

ICE and OTC voice brokers, but the ClearPort swaps made 

prices publicly visible. 

181 Volumes transacted on ICE are potentially a subset of the volume reported 

to Gas Daily. Given the data available, OMOI does not know the size of the 

ICE volumes reported by market participants to Gas Daily. 182 In March 2003, the CCRO issued transition guidelines to help increase the 

amount of data supplied to index developers. 183 Docket No. AD03-7 184 In response to requests for Commission action, the Commission issued the 

Policy Statement on Natural Gas and Electric Price Indices, July 24, 2003. The 

Policy Statement presented guidelines for both index developers and price 

reporters. In addition, the Commission provided assurance to companies 

that, if they follow the Policy Statement guidelines, they will not be subject to 

penalties for inadvertent errors. In October 2003, the Commission conducted 

a survey of 266 energy companies to determine whether, how, and to what 

extent they report price data to index developers. 185 For example, “tier 1” in Gas Daily is for locations with volumes of at least 

100,000 MMBtu/d and at least 10 trades. 186 Unlike the day-ahead natural gas product, only ICE published the specific 

volumes, number of transactions and number of counterparties for monthahead physical natural gas products per delivery point for the months of 

the assessment period
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

94

Source: Platts Gas Daily for Nymex forward curve. Analysis and graphic by OMOI.

Investment

Forward Price Expectations 

and Production

Forward price expectations increased in 2003, sending 

signals to investors that higher natural gas prices might be 

sustainable and additional investment might be justified. 

Figure 61 displays the forward 36 month futures settlement 

prices on given days during the assessment period. In 

September 2002, the forward curve was centered at about 

the $4.00/MMBtu price level. By February 2003, the forward 

curve had shifted up. Prices were at their highest level for 

the first several months (March and April 2003) on the 

curve due to prolonged cold weather, low storage levels and 

pipeline constraints. The short-term supply and demand 

factors from February 2003 subsided and were replaced by 

longer-term concerns about the supply of natural gas and 

refilling storage for the 2003–04 heating season, reflected 

in price increases in early June 2003. The futures forward 

curves and their implied volatility are important because 

they influence the decision-making of industry participants 

to drill for natural gas, employ physical hedges like natural 

gas storage injections, engage in forward financial hedging 

transactions or sponsor infrastructure projects (e.g., LNG 

regasification terminals and related storage facilities). 

Despite higher gas prices since early-2003, a limited 

new supply response resulted. Increases in gas-directed 

drilling by producers in North American did not match 

peak 2001 rig counts (see Figure 62) and drilling did 

not substantially relieve tightness in the overall North 

American supply and demand balance. Significant investments in upstream activity began to be made; companies 

dedicated about 900 gas-directed rigs to drilling at the 

end of the assessment period in response to expectations of 

higher natural gas prices (shown in Figure 62). Several factors, 

however, may account for why recent high gas prices have not 

stimulated more gas-directed drilling, including the following: 

 Companies have dedicated a portion of incremental revenues from high gas prices to strengthen balance sheets 

instead of deploying more rigs.187

 Companies may have delayed upstream capital commitments due to uncertainty about the sustainability of 

current price levels and extreme price volatility.

 Earnings associated with developing mature geologic 

plays in the United States may be less favorable to “supermajor” producers than making investments abroad.

Figure 61: In 2003, forward price expectations shift upward.

187 CERA, “Can We Drill Our Way Out of the Supply Shortage,” Decision Brief, 

October 2003 and follow-up teleconference call with CERA in October 2003. 
S T A T E O F T H E M A R K E T S

95

Figure 62: 2003 producer drilling response to high prices moderate.

Note: Prices not adjusted for inflation.

Source: Platts GASdat, Platts Gas Daily and Baker-Hughes. Analysis and graphic by OMOI.

Figure 63: More drilling needed to maintain production.

Note: Daily wet gas production from gas wells, by year of production start, total U.S.

Source: NPC, “Balancing Natural Gas Policy,” September 2003.

 Restrictions on access to natural gas resources located on public lands may have foreclosed investment 

opportunities.188

188 NPC, “Balancing Natural Gas Policy: Fueling the Demands of a Growing 

Economy,” September 2003. 
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

96

Figure 64: Map and output capacities of existing and proposed LNG terminals.

Existing Terminals with Expansions

A. Everett, MA 1.0 Bcfd Tractebel

B. Cove Point, MD 1.0 Bcfd Dominion

C. Elba Island, GA 1.2 Bcfd El Paso

D. Lake Charles, LA 1.2 Bcfd Southern Union

Approved Terminals

1. Hackberry, LA 1.5 Bcfd Sempra Energy

2. Port Pelican 1.6 Bcfd ChevronTexaco

3. Bahamas 0.8 Bcfd AES Ocean Express*

4. Gulf of Mexico 0.5 Bcfd El Paso Global

Proposed Terminals – FERC

5. Bahamas 0.8 Bcfd Calypso Tractebel

6. Freeport, TX 1.5 Bcfd Cheniere/Freeport LNG Dev.

7. Fall River, MA 0.8 Bcfd Weaver’s Cove Energy

8. Long Beach, CA 0.7 Bcfd SES/Mitsubishi

9. Corpus Christi, TX 2.6 Bcfd Cheniere LNG Partners

10. Sabine, LA 2.6 Bcfd Cheniere LNG

11. Corpus Christi, TX 1.0 Bcfd Vista Del Sol/ExxonMobil

12. Sabine, TX 1.0 Bcfd Golden Pass/ExxonMobil

13. Logan Township, NJ 1.2 Bcfd Crown Landing LNG – BP

Proposed Terminals – Coast Guard

14. California Offshore 1.5 Bcfd Cabrillo Port – BHP Billiton

15. Louisiana Offshore 1.0 Bcfd Gulf Landing – Shell

Planned Terminals

16. Brownsville, TX N/A Cheniere LNG Partners

17. Humboldt Bay, CA 0.5 Bcfd Calpine

18. Mobile Bay, AL 1.0 Bcfd ExxonMobil

19. Somerset, MA 0.7 Bcfd Somerset LNG

20. Louisiana Offshore 1.0 Bcfd McMoRan Exp.

21. Belmar, NJ Offshore N/A El Paso Global

22. So. California Offshore 0.5 Bcfd Crystal Energy

23. Bahamas 0.5 Bcfd Seafarer - El Paso/FPL

24. Altamira, Tamulipas 1.1 Bcfd Shell

25. Baja California, MX 1.0 Bcfd Sempra & Shell

26. Baja California 0.6 Bcfd Conoco-Phillips

27. Baja Calif. Offshore 1.4 Bcfd ChevronTexaco

28. Baja California 0.6 Bcfd Marathon

29. California – Offshore 0.5 Bcfd ChevronTexaco

30. St. John, NB 0.8 Bcfd Irving Oil & Chevron Canada

31. Point Tupper, NS 0.8 Bcfd Access Northeast Energy

32. Harpswell, ME 0.5 Bcfd Fairwinds LNG – CP & TCPL

33. St. Lawrence, QC N/A TCPL and/or Gaz Met

34. Lázaro Cárdenas, MX 0.5 Bcfd Tractebel

35. Gulf of Mexico 1.0 Bcfd ExxonMobil

36. Providence, RI 0.5 Bcfd Keyspan & BG LNG

37. Mobile Bay, AL 1.0 Bcfd Cheniere LNG Partners

Note: *U.S. pipeline approved; LNG terminal pending in Bahamas

Source: FERC. Graphic by OMOI.
S T A T E O F T H E M A R K E T S

97

Decline Rates of Production

While drilling activity appears to have begun to accelerate at the end of the assessment period, leading to increased 

production, recoveries per natural gas completion have 

diminished. New production has tended to have a higher 

initial rate due to improved technology, thereby increasing 

cash flow. However, higher initial production has tended to 

result in increased production decline rates, especially when 

coupled with smaller recoveries per natural gas well completion due to declining reservoir quality. This creates the need 

for more drilling to maintain production, as shown in Figure 

63. In other words, each additional well increases production for a shorter period of time and a higher rig count is 

required to maintain production. 

The reliance on aggressive drilling to maintain production has led to concerns that supply growth in traditional 

areas, mainly in the Rockies and Gulf of Mexico shelf, will 

only serve to offset accelerating decline rates and that largescale resources such as LNG and Arctic natural gas will be 

required to meet future demand.

LNG Investment

Natural gas market fundamentals have helped renew 

interest in LNG as a source of North American supply during 

the assessment period. Higher natural gas prices increased 

imports of LNG at existing U.S. import terminals and companies proposed the development of more than 30 LNG receipt 

terminals in North America, which appear to offer profitable 

opportunities189 for growth.190 Improvements in technology 

and international competition drove costs of importation 

to $2.50–$4.00/MMBtu for greenfield projects.191 Figure 

64 shows the location and capacity of proposed new LNG 

import terminals.

The potential to implement the proposed investments 

will depend on many factors. The number of projects 

actually realized will be less than those announced. First, 

investors and lenders must be convinced that higher natural 

gas prices are sustainable, be able to manage risk through 

a derivative contract or find a creditworthy counterparty 

willing to enter into a long-term contract. Second, project 

customers must be creditworthy and willing to commit to 

long-term contracts. While long-term contracts are also 

necessary for pipeline investments, the $2 billion–$5 billion 

investment required for a complete LNG train magnifies the 

challenge of securing sufficient contract commitments. 

Siting and permitting factors may slow LNG development. Certification and assessments conducted by multiple 

federal authorities, including FERC, EPA, DOE, the U.S. Coast 

Guard and the State Department and state and local authorities, can be a multi-year process. To expedite the process, the 

Commission is coordinating with the U.S. Coast Guard and 

the Department of Transportation through an inter-agency 

working group designed to provide seamless review of project 

siting, safety and security. The NPC is seeking certification 

permitting periods of one year or less.192 Locally, substantial 

work will be needed to address security and environmental 

concerns of multiple jurisdictions and communities. 

Storage Capacity Investment

Historically, as detailed in Table 21, most working gas in 

storage is controlled by LDCs.

Investment in new storage capacity was slow during 

the assessment period. Capacity additions to storage have 

leveled off in the past few years. Total underground storage 

capacity increased 1.4 percent (116 Bcf) in 2001 from 2000. 

The increase from 2001 to 2002 was 0.3 percent (23 Bcf). 

The Commission certificated about 53 Bcf of new storage 

capacity and nearly 3 Bcfd of deliverability during the 

assessment period. 

Recent storage additions, including the Lodi and Wild 

Goose facilities in California, illustrate that market particiTable 21: Storage capacity control shares by category of users.

Category of storage 

capacity user

Share of storage capacity 

controlled

Local distribution companies 73%

Pipelines 8%

Others (marketers, generators, etc.) 19%

Source: International Gas Consulting, “The Evolution of Underground Natural Gas Storage: Changes in Utilization Patterns,” submitted to the 

American Gas Association, August 2001. 

189 Ibid, p. 3. 190 Marie N. Fagan, CERA, “Can We Drill Our Way Out of the Supply Shortage,” 

North American Natural Gas, p. 1, October 2003. 191 Scott, Madden & Associates, Energy Industry Update: Highlights of 

Significant Trends and Emerging Trends in the Energy Industry, 2003, p. 18. 192 NPC, “Balancing Natural Gas Policy: Fueling the Demands of a Growing 

Economy,” Volume I, Summary of Findings and Recommendations, 

September 2003, p. 64. 
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

98

pants continued to find value in storage investments. Lodi 

and Wild Goose are owned by independent storage developers who are typically aggressive users of storage facilities, 

using multi-cycle, high-deliverability facilities to execute 

gas pricing arbitrage strategies and hub-to-hub trading 

activities.193 Nevertheless, the slow rate of recent storage 

capacity additions may reflect the many challenges to storage 

investment, especially nontraditional, high-deliverability 

storage. These investment hurdles include finding, acquiring 

and developing a site with suitable geologic characteristics, 

establishing binding, long-term firm contracts for capacity 

services, managing the regulatory process and securing 

financing and counter-party credit.

A regulatory issue for storage developers was illustrated 

in the recent Red Lake Storage application to construct 

and operate facilities in Mohave County, Ariz. and the 

request to charge market-based rates for the facilities.194

The Commission denied the request for market-based rates 

because of a lack of comparable services in the geographic 

area and, hence, the potential for market power. This 

demonstrates a paradox in that a developer was not able 

to get market-based rate approval in a region because it 

was lacking in storage alternatives. The result is that in the 

areas most needing storage, denying market-based rates may 

potentially hinder development. Another regulatory concern 

is that LDCs hesitate to make the long-term commitments to 

secure natural gas supplies (and therefore support infrastructure investments such as storage) when retail unbundling 

creates uncertainty about their natural gas requirements.

The ability to secure long-term capacity contracts for 

storage was further limited by the credit problems of some 

Figure 65: FERC certifications signal new pipeline investments.

Note: Map includes major pipeline projects (70 MMcfd or greater) certificated from Jan. 1, 2002 to June 30, 2003.

Source: FERC. Graphic by OMOI.

193 International Gas Consulting, “The Evolution of Underground Natural Gas 

Storage: Changes in Utilization Patterns,” submitted to the American Gas 

Association, page 27-28, August 2001. 194 103 FERC 61277, (Order Denying rehearing of FERC’s Jan. 30, 2003 Order 

& Terminating proceedings regarding Red Lake Gas Storage, LP under 

docket CP02-420 et al). 
S T A T E O F T H E M A R K E T S

99

of the customers, especially power generators. Valuing 

multi-cycle, high-deliverability storage is more difficult 

than assigning quantitative value to pipeline and generation 

assets. Given its higher cost, the economics of high-deliverability storage are dependent upon deriving trading benefits 

from volatility in addition to the traditional seasonal 

arbitrage. The advantages of trading around volatility or real 

option value have been difficult to quantify, especially with 

the collapse in the wholesale trading sector and corresponding reduced liquidity. 

Substitutes for storage may have been a deterrent to 

increased investment. For example, development of new 

pipeline capacity infrastructure partially reduces the need 

for natural gas storage capacity, as does remarketed pipeline 

capacity bundled with supply and marketed as a peaking 

service. Market participants could also choose from an 

assortment of financial product offerings to hedge price risk 

without using physical instruments like storage.

Pipeline Investment

Substantial natural gas pipeline infrastructure was 

certificated during the assessment period, primarily to 

meet the needs of power generators. As shown in Figure 

65, pipeline companies’ investment plans are demonstrated 

by the 2,234 miles of pipeline (capacity of 7.4 Bcfd with an 

estimated cost of $4.6 billion) certificated by the Commission 

during the assessment period. Though this represents a 

significant level of new investment, it is a decline from 2001, 

when 3,044 miles of pipeline (9.5 Bcfd with an estimated 

cost of $5 billion) were certificated. 

Several major pipelines that expanded service or came 

on line as greenfield systems during the assessment period 

had power generation “anchor” shippers. For example, 

power generation shippers accounted for nearly 86 percent 

(or 3.6 Bcfd out of 4.2 Bcfd) of capacity subscribed on a 

firm basis in a sample of pipeline certification applications 

approved by FERC since 2001 (identified in Figure 66).195

Nevertheless, certificated projects will only go forward 

if they secure the support of buyers, can be justified by 

market signals, can be financed and receive federal, state 

and local regulatory approvals. Before market participants 

contractually commit to a project, forward market basis 

values or swaps along key pipeline corridors need to signal 

that added capacity is needed and likely to be profitable. 

For instance, even with the Kern River capacity expansion, 

financial basis differentials in the Rockies continue to 

justify new pipeline construction within the next two years, 

as shown in Figure 67. Similarly, other western locations, 

such as the San Juan Basin, demonstrate basis differentials 

that would justify investment. The following chart shows 

the settlement values of the basis differentials for SoCal to 

both San Juan and Opal as compared to the Kern and 

Figure 66: New pipeline firm subscribers mostly power generation shippers.

Source: FERC, interstate natural gas pipeline applications for Certificates of Public Convenience and Necessity. Graphic and further analysis by OMOI.

195 OMOI has not attempted to estimate interruptible transportation usage on 

pipeline systems that have recently been expanded or built. 
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

100

El Paso tariff rates for firm transportation. The convergence 

of the basis and tariff values for SoCal-Kern/Opal and 

SoCal-El Paso (San Juan) by the end of 2005 tends to 

support investment in new pipeline construction. 

Another indicator of the forward market’s role in signaling the need for infrastructure development can be seen in 

basis trading. The projected basis differential between Henry 

Hub and Transco Zone 6-NY, seen in Nymex’s ClearPort 

activity for October 2003 settlements, indicates that the 

average market value of pipeline capacity from the Gulf 

Coast is comparable to the tariff rate plus fuel for Transco, 

the low cost carrier from the Gulf Coast (see Figure 68). This 

differential indicates some firm market valuation, but does 

not fully support new construction, which would be more 

costly than the existing firm transportation on Transco. 

Despite considerable investment in new capacity during 

the assessment period, the pace of new investments slowed 

in comparison to prior periods, as evidenced by levels of 

certificated pipelines. In addition, this slowdown is also seen 

in delayed or cancelled projects, such as Independence and 

the related Supply Link. Approximately 6.1 Bcfd of major 

pipeline expansion projects have been delayed and cancelled 

since 2001. Reduced expectations for incremental projects to 

serve power generation, the slowing of the economy, a lack 

of long-term contractual support by financially distressed 

marketers, environmental concerns and competition from 

other recently completed projects all were likely contributors 

to the slower pace of new additions. 

Market factors made it more difficult for shippers to 

contract for pipeline capacity. Gas-fired generators, faced 

with difficulties in executing long-term purchased power 

agreements and low average spark spreads for off-peak 

and peak periods, were unable to generate the cash flows 

needed to contract for the long term, firm natural gas 

transportation rights needed to anchor new investment in 

pipelines. The counterparty credit exposure to pipelines 

from capacity buyers who were under financial stress and 

had poor credit ratings continued to evolve during the 

assessment period. While traditional natural gas distribution customers typically have strong credit, the weakened 

status of marketing and generation companies raised 

concerns. Many wholesale marketers and merchant power 

producers no longer had the credit to make long-term 

financial commitments. During the assessment period, only 

six of the 23 merchant companies that Standard and Poor’s 

rates had stable outlooks, and the rating agency does not 

foresee much improvement for the companies.196

The decline in shipper credit ratings led pipelines 

to strengthen credit terms.197 During the assessment 

period, the Commission’s natural gas pipeline credit 

policy provided a standard of security to the pipelines, 

for non-creditworthy customers, equal to three months 

demand charges. This is comparable to the time required 

to shut-in a non-paying customer, thus minimizing any 

pipeline exposure to uncollectible receivables. The credit 

requirements are up to 12 months pre-payment of demand 

charges for new pipelines, generally to satisfy lenders’ 

requirements for financing new construction.

Figure 67: New Rockies investment still justified by basis differentials.

Source: Nymex ClearPort, pipeline tariffs, October 2003. Analysis and graphic by OMOI.

196 Standard & Poor’s, “Refinancing Needs and Poor Credit Still Challenges the 

Energy Merchant Sector,” www.riskcenter.com, Oct. 27, 2003. 197 Including Docket Nos. GT02-35-00, GT02-38-00, RP03-7-000, RP03-64-000, 

RP03-70-000, RP03-162-000 and RP02-363-003.
S T A T E O F T H E M A R K E T S

101

Summary of Natural Gas

Market Performance

Based on the analysis detailed above, we conclude that 

natural gas markets performed relatively well in that they 

continued to deliver product to customers despite supply 

tightness. In addition, investment levels appeared reasonable given market signals and conditions. Nevertheless, the 

increase in price and volatility levels observed in the assessment period strained some buyers and, if sustained, could 

have longer-term adverse economic effects. Further progress 

in the future on issues of price transparency, liquidity and 

forward market development needs to continue.

Figure 68: Projected Henry Hub to Transco Zone 6-NY basis does not support new construction.

Source: Nymex ClearPort, October 2003. Analysis and graphic by OMOI.

103

A P P E N D I C E S

Appendix 1: REGIONAL MAPS

Figure 69: Map of ISO-NE.

Source: Platts POWERmap. Graphic by OMOI.
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

104 

Figure 70: Map of NYISO.

Source: Platts POWERmap. Graphic by OMOI.

Figure 71: Map of PJM.

Source: Platts POWERmap. Graphic by OMOI.
105

A P P E N D I C E S

Figure 72: Map of the Southeast.

Source: Platts POWERmap. Graphic by OMOI.

Figure 73: Map of Florida.

Source: Platts POWERmap. Graphic by OMOI.
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

106 

Figure 74: Map of the Midwest.

Source: Platts POWERmap. Graphic by OMOI.

Figure 75: Map of South Central.

Source: Platts POWERmap. Graphic by OMOI.
107

A P P E N D I C E S

Figure 76: Map of ERCOT.

Source: Platts POWERmap. Graphic by OMOI.

Figure 77: Map of the Southwest.

Source: Platts POWERmap. Graphic by OMOI.
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

108 

Figure 78: Map of the Northwest.

Source: Platts POWERmap. Graphic by OMOI.

Figure 79: Map of CAISO.

Source: Platts POWERmap. Graphic by OMOI.
109

A P P E N D I C E S

GENERATING CAPACITY

ADDITIONS Appendix 2:

Table 22: Generating capacity additions and reserve margins.

Region Capacity 

additions (MW)

Regional 

capacity percent 

increase

Regional increase as a percent of 

total U.S. additions

2002 reserve 

margin

ISO-NE 4,159 14.4% 4.9% 17%

NYISO 316 0.9% 0.4% 17%

PJM 7,458 8.8% 8.8% 13%

ERCOT 8,874 10.1% 10.4% 31%

CAISO 5,726 10.5% 6.7% 33%

Southeast 25,728 14.1% 30.3% 15%

Florida 4,466 10.4% 5.3% 20%

Midwest 14,471 7.8% 17.0% 28%

South Central 3,749 8.5% 4.4% 21%

Southwest 7,103 22.7% 8.4% 13%

Northwest 2,918 4.5% 3.4% 40%

Total 84,967 10.1% 100.0%

Source: New capacity data derived from Energy Information Administration, Form EIA-860, “Annual Electric Generator Report.” Regional Baseline 

capacity for percentage increase calculation as of Dec. 31, 2001. Reserve margin data from FERC; NERC ES&D Database; NERC 2002 Summer 

Assessment; NERC 2003 Summer Assessment, Summary of Estimated Loads and Resources; Western Electricity Coordinating Council, July 2003; 

ISO-NE website; PJM website; NYISO Load & Capacity Outlook, March 2002 and observed peak demand July 29, 2002. Appendix 3: Generation 

Ownership Concentration in Regional Electricity Markets
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

110 
111

A P P E N D I C E S

GENERATION OWNERSHIP

CONCENTRATION IN

REGIONAL ELECTRICITY

MARKETS

Appendix 3:

Figure 80–Figure 96: Note: Installed capacity is the measured capacity or the capacity demonstrated to have been available 

during the hour of highest output of a generating unit. For purposes of this analysis, the working definition of a peaking unit 

is a natural gas or oil-fired unit with a heat rate greater than 10,000 Btu/kWh or a combustion turbine or internal combustion 

unit smaller than 50 MW in size with no reliable heat rate information reported. MWh produced is the net generation of an 

electric generating unit, or the amount of gross generation less the electrical energy consumed at the generating station(s) for 

station service or auxiliaries. Electricity required for pumping at pumped-storage plants is regarded as electricity for station 

service and is deducted from gross generation. Source: Platts POWERdat, Modeled Production Costs-Ownership-Based dataset 

for calendar year 2002. Analysis and graphics by OMOI.

A. Regions with organized markets

Figure 80: Generation ownership concentration in ISO-NE.
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

112 

Figure 81: Generation ownership concentration in NYISO.

Figure 82: Generation ownership concentration in PJM.

Figure 83: Generation ownership concentration in ERCOT.
113

A P P E N D I C E S

Figure 84: Generation ownership concentration in CAISO.

B. Regions without organized markets

Figure 85: Generation ownership concentration in the Southeast (Southern).

Figure 86: Generation ownership concentration in the Southeast (Entergy).
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

114 

Figure 87: Generation ownership concentration in the Southeast (VACAR).

Figure 88: Generation ownership concentration in the Southeast (TVA).

Figure 89: Generation ownership concentration in Florida (FRCC).
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A P P E N D I C E S

Figure 90: Generation ownership concentration in the Midwest (ECAR).

Figure 91: Generation ownership concentration in the Midwest (MAIN).

Figure 92: Generation ownership concentration in the Midwest (MAPP).
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

116 

Figure 93: Generation ownership concentration in South Central (SPP).

Figure 94: Generation ownership concentration in the Southwest (RMPA).

Figure 95: Generation ownership concentration in the Southwest (AZ-NM-SNV).
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A P P E N D I C E S

Figure 96: Generation ownership concentration in the Northwest (NWPP).
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

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119

A P P E N D I C E S

DESCRIPTION OF

NATURAL GAS MARKETS

AND PRODUCTS

Appendix 4:

T

he North American natural gas market is 

an integrated system of geographic markets 

that provides physical, financial and 

transportation products.

Physical products are defined by the geographic 

point of origin or the delivery points, typically market 

centers and hubs on the transportation system, where gas 

volumes are metered and other services are provided. The 

most well known geographic point for defining a product 

is the Henry Hub, the longest operating physical hub in 

the United States. Physical products are also delineated by 

the term of delivery—daily (spot), monthly, mid-term (e.g., 

for the next winter or summer season). 

Pipeline products enable a purchaser of physical gas 

to transport the product to the desired destination. Firm 

transportation, the primary market service under which 

gas moves to market, provides for guaranteed delivery of 

gas in all events short of force majeure. Customers that 

can switch quickly to alternative fuels such as fuel oil (e.g., 

commercial, industrial and power generators) usually opt 

for interruptible gas transportation, which is subject to 

peremptory flow suspensions to make way for gas flowing 

under firm contracts.

Firm transportation customers can resell their 

capacity to other shippers, in the secondary market. The 

most common secondary market transactions are capacity release, transactions that enable firm shippers to let 

others use their capacity rights for a fee. The secondary 

market allows primary capacity holders to recoup at least 

some of the investment they have in capacity contracts 

and thereby offset the cost of reserving year-round capacity that they may not fully use. And it allows participants 

who have not made firm commitments to obtain capacity, 

sometimes at discounts or at least without long-term obligations. If the seller bundles the transportation service 

with physical product, the transaction may be considered 

“gray market,” i.e., the transportation cost is not transparent in a bundled transaction. 

Financial derivative products complement the physical products by enhancing market flexibility, providing participants opportunities to manage risks associated with the 

ownership of the physical commodity and to participate in the 

market for speculative purposes. Natural gas financial products include futures, options and swaps. Financial derivative 

products, like physical products, are defined by geographic 

delivery location, usually Henry Hub, prices tied to that location and term (balance of the month, next month, a series of 

months or yearly). 

Financial products, most notably the New York 

Mercantile Exchange (Nymex) futures contract, provides 

a source of price discovery to the market. The Nymex 

contract trades forward futures for six consecutive years 

and provides a benchmark price within many physical and 

financial contracts. For instance, Nymex natural gas futures 

contracts and over-the-counter (OTC) basis swaps allow for 
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

120 

the hedging of both commodity price risk and also basis 

or the imputed value of pipeline capacity. Other financial 

instruments such as options allow guaranteed prices even 

for uncertain volume requirements. 

In addition to futures, options and swaps 

on Nymex, which is a regulated exchange, there is an 

OTC market for natural gas financial products. Activity 

on the OTC market is executed primarily through 

IntercontinentalExchange (ICE, an internet trading platform), voice brokers and direct bilateral transactions.
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A P P E N D I C E S

ELECTRIC POWER FUEL

CONSUMPTION TRENDS Appendix 5:

Figure 97: Overall electricity generation variable but continues to rise.

Note: Excludes pumped storage hydro.

Source: Monthly Energy Review, Table 7.2b, EIA, November 2003. Analysis and graphic by OMOI.
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

122 

As shown in Figure 97, overall electricity generation 

increased about 0.7 percent between the first six months 

of 2002 and the first six months of 2003 even though the 

composition of fuels consumed changed substantially. A 2.9 

percent increase in coal generation (26,124 million kWh) 

and a 45 percent increase in petroleum generation (17,769 

million kWh) offset percentage decreases in generation 

sourced by natural gas (9 percent or 24,295 million kWh) 

and nuclear (2.7 percent or 10,230 million kWh) as shown in 

Figure 98. Fuel switching from oil to gas explains part of the 

decline in gas-fired generation during the first half of 2003 

compared to 2002 and increased generation by coal units 

and other fundamental factors (especially cooler weather) 

also explain the relative decline. 

Figure 98: Recent increases in coal and petroleum fuel use offset declines in gas use.

Notes: Comparison of January 2002–June 2002 and January 2003–June 2003. Excludes pumped storage hydro.

Source: Derived from Monthly Energy Review, Table 7.2b, EIA, November 2003. Analysis and graphic by OMOI.
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A P P E N D I C E S

GAS AND ELECTRIC

PRICE POINTS Appendix 6:

Figure 99: Approximate locations of gas and electric price points.

Source: Platts POWERmap. Analysis and graphic by OMOI.
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

124 
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A P P E N D I C E S

LIST OF ACRONYMS AND

ABBREVIATIONS Appendix 7:

AEP American Electric Power

AMP Automated mitigation procedures

ARR Auction revenue rights

ATC Available transfer capability

AZ-NM-SNV Arizona-New Mexico-Southern Nevada 

(NERC subregion)

Bcf Billion cubic feet

Bcfd Billion cubic feet per day

Btu British thermal unit

CAISO California ISO

CA-MX California-Mexico (NERC subregion)

CC Combined cycle

CCRO Committee of Chief Risk Officers

CERA Cambridge Energy Research Associates

CERS California Energy Resources Scheduling 

CFTC Commodity Futures Trading Commission

COB California-Oregon Border

COOP Cooperative

CT Combustion turbine

DA Day-ahead

DCA Designated congestion area

DEC Decremental (energy)

DOE Department of Energy

DPL Delmarva Peninsula

ECAR East Central Area Reliability Coordination 

Agreement (NERC region)

EFP Exchange of futures for physical

EFS Exchange of futures for swaps

EIA Energy Information Administration

EQR Electric Quarterly Report

ERCOT Electric Reliability Council of Texas 

(NERC region)

FERC Federal Energy Regulatory Commission

FRCC Florida Reliability Coordinating Council 

(NERC region)

FTR Financial transmission right

GISB Gas Industry Standards Board

GW Gigawatt (one billion watts)

GWh Gigawatt-hour (one billion watt-hours)

ICAP Installed capacity

ICE IntercontinentalExchange

INC Incremental (energy)

INP Indian Point (nuclear plant in NYISO)

IPP Independent power producer
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

126 

ISDA International Swap Dealers Association

ISO Independent system operator

ISO-NE ISO New England

JOA Joint operating agreement

kWh Kilowatt-hour (one thousand watt-hours)

LBMP Locational-based marginal price

LDC Local distribution company

LIPA Long Island Power Authority

LMP Locational marginal price

LNG Liquefied natural gas

LSE Load serving entity

MAAC Mid-Atlantic Area Council (NERC region, 

geographically within PJM)

MAIN Mid-America Interconnected Network 

(NERC region)

MAPP Mid-Continent Area Power Pool 

(NERC region)

MISO Midwest Independent Transmission 

System Operator

MMBtu Million British thermal units

MMG Market Monitoring Group (in ISO-NE)

MMU Market monitoring unit

MW Megawatt (one million watts)

MWh Megawatt-hour (one million watt-hours)

NAESB North American Energy Standards Board

NEMA Northeast Massachusetts

NEPOOL New England Power Pool

NERC North American Electric Reliability Council

NGX Natural Gas Exchange (in Canada)

NP-15 North of Path 15 (in CAISO)

NPC National Petroleum Council

NPCC Northeast Power Coordinating Council 

(NERC region, geographically includes ISO-NE 

and NYISO)

NWPP Northwest Power Pool (NERC subregion)

NY New York

NYC New York City

NYISO New York Independent System Operator

Nymex New York Mercantile Exchange

NYPP New York Power Pool

NYSERDA New York State Energy Research and 

Development Authority

O&M Operations and maintenance

OMOI Office of Market Oversight and Investigations 

(FERC)

OOM Out of market

OOS Out of sequence

OTC Over the counter

PG&E Pacific Gas & Electric

PJM PJM Interconnection 

PUSH Peaking Unit Safe Harbor

PX Power Exchange (formerly in CAISO)

RMPA Rocky Mountain Power Area 

(NERC subregion)

RMR Reliability must run

RSI Residual supply index

RT Real-time

RTEP Regional Transmission Expansion Plan

RTO Regional transmission organization

RTS Real-time scheduling

SCE Southern California Edison

SERC Southeastern Electric Reliability Council 

(NERC region, includes Entergy, Southern, 

TVA and VACAR)

SoCal Southern California

SP-15 South of Path 15 (in CAISO)

SPP Southwest Power Pool (NERC region)

SWCT Southwest Connecticut

TLR Transmission loading relief

Transco Transcontinental Gas Pipe Line

TVA Tennessee Valley Authority (NERC subregion)

VACAR Virginia-Carolinas area (NERC subregion)

VAP Dominion-Virginia Power

VIU Vertically integrated utility

VRD Virtual regional dispatch

WECC Western Electricity Coordinating Council 

(NERC Region)

WUMS Wisconsin-Upper Michigan subregion

ZP-26 Zone at Path 26 (in CAISO)
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A P P E N D I C E S

Appendix 8: GLOSSARY

12-month strip: Prices for the next 12 months of consecutive natural gas futures trading contracts, usually 

starting with the nearest, or prompt, month. 

Ancillary services: Those services necessary to support 

the transmission of electric power from seller to 

purchaser given the obligations of control areas 

and transmitting utilities within those control 

areas to maintain reliable operations of the 

interconnected transmission system. Ancillary 

services supplied with generation include: load 

following, reactive power-voltage regulation, 

system protective services, loss compensation 

service, system control, load dispatch services and 

energy imbalance services. 

Arbitrage: The simultaneous purchase of a commodity/

derivative in one market and the sale of the same, 

or similar, commodity/derivative in another market 

in order to exploit price differentials. 

Assessment period: The time period between Jan. 1, 2002 

and June 30, 2003 for the purposes of this report. 

Auction Revenue Right: An ARR entitles its holder to 

receive a share of revenues from the auction of a 

corresponding financial transmission right (FTR).

Automatic generation control: The automatic regulation 

of the power output of electric generators within a 

prescribed range in response to a change in system 

frequency, or tie-line loading, to maintain system 

frequency or scheduled interchange with other 

areas within predetermined limits. 

Automated mitigation control: A procedure under which 

the bids of individual suppliers would be capped 

under certain pre-determined conditions. As 

implemented in New York, this procedure is triggered when the locational marginal price exceeds 

$150/MWh. Individual bids are then subject to a 

conduct test and an impact test. The conduct test 

is failed if the bid exceeds a threshold based on a 

predetermined “reference bid.” The impact test is 

failed if the change in the market-clearing price, 

using reference bids in place of actual bids, exceeds 

a certain threshold. 

Balancing: The requirement imposed by electricity grids or 

natural gas pipelines that supply and demand be 

equal over a certain time period. 

Baseload: The minimum amount of electric power delivered 

or required over a given period of time at a steady 

rate. The minimum continuous load or demand in 

a power system over a given period of time. 

Baseline: In electric markets, baseline refers to an 

agreed-upon level of electricity consumption from 

which deviations are measured. Baselines are 

usually based on a customer’s historical usage. The 

variation in usage from the baseline may be billed 

at a different rate. 
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128 

Basis: The price difference between a natural gas price 

point (e.g., a market hub, citygate or supply 

receipt area) and a reference point, most often 

Henry Hub. Financial basis refers to the difference between the futures expiration price and 

the monthly cash price index at Henry Hub or at 

another geographical point. 

Bid-ask differential: The difference in price between what 

a buyer offers to pay for a commodity and what a 

seller offers to accept for a commodity. 

Bilateral physical electricity transaction: A direct contract 

between an electric power producer and either a 

user or broker outside of a centralized power pool 

or power exchange. 

Bus: A conductor or group of conductors that serve as a 

common connection for two or more electric 

circuits within a station. 

Capacity margin: The amount of capacity above planned 

peak system demand available to provide for scheduled maintenance, emergency outages, system 

operating requirements, and unforeseen demand. 

Capacity markets: Markets designed to allow companies 

with an obligation to deliver electricity to customers to competitively procure contracts with power 

plant owners to have their units up and running 

and able to produce additional energy. 

Clearing: The registration and settlement of a trade that 

includes provisions for margin requirement and 

performance guarantee. 

Combined-cycle generators: Power generating units 

that increase the efficiency of electric generation 

by capturing and reusing waste heat; the latest 

units achieve heat rates near 6,000 Btu/kWh 

with more than 50 percent fuel-to-electricity 

conversion efficiency. 

Congestion: A characteristic of the transmission system 

produced by a constraint on the optimum 

economic operation of the power system, such 

that the marginal price of energy to serve the next 

increment of load, exclusive of losses, at different 

locations on the transmission system is unequal. 

Congestion costs: Charges assessed and redistributed due 

to electrical transmission network constraints. 

Control area: An electric power system or combination 

of electric power systems to which a common 

automatic control scheme is applied in order to: 

(1) match, at all times, the power output of the 

generators within the electric power system(s) 

and capacity and energy purchased from entities 

outside the electric power system(s), with the 

load in the electric power system(s); (2) maintain, 

within the limits of Good Utility Practice, scheduled interchange with other Control Areas; (3) 

maintain the frequency of the electric power 

system(s) within reasonable limits in accordance 

with Good Utility Practice; and (4) provide sufficient generating capacity to maintain operating 

reserves in accordance with Good Utility Practice. 

Cooling degree days: A measure of cooling energy demand 

determined by how far a location’s temperature 

averaged above 65 degrees Fahrenheit. 

Credit clearing: A mechanism for settling mutual claims, 

the result of which is that the risk that a company 

might fail to fulfill its contract is pooled among 

many companies. 

Credit rating: A statistical technique wherein several financial characteristics are combined to form a single 

score to represent a customer’s creditworthiness. 

Credit risk: The risk that an issuer of debt securities or a 

borrower may default on his obligations, or that 

the payment may not be made on a negotiable 

instrument. 

Critical notices: Pipeline issuances that provide information 

on conditions that affect natural gas scheduling or 

adversely affect scheduled gas flow. 

Curtailable load: Electricity deliveries that are subject to 

interruption by the grid operator. 

Day-ahead markets: Forward markets for electricity or 

natural gas to be supplied the following day.

Debt financing: Providing the necessary capital by selling 

bonds, bills or notes to individuals or institutions. 

Demand elasticity: The demand response, or lack thereof, 

of customers as a result of a change in price. 

Demand responsiveness/demand response: A situation 

that occurs when customers respond to an increase 

in price, or a grid operator’s call for emergency 

relief, by lowering demand for a good or service 

and respond to a decrease in price by increasing 

demand for a good or service. 

Dispatch declines: The 16 categories for which a generator 

may decline a dispatch instruction in CAISO’s automated dispatch system, e.g., safety, unit derating 

or environmental constraints. If an automated 

dispatch instruction is not responded to within two 

minutes, it is considered declined. 

Dual-fueled (or dual-fired) unit: A generating unit that 

can produce electricity using two or more fuels. 
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A P P E N D I C E S

In some of these units, only the primary fuel can 

be used continuously; the alternate fuel(s) can be 

used only as a start-up fuel or in emergencies. 

Economic withholding: An exercise of market power 

intended to raise the market price above competitive levels by pricing offer blocks high enough to 

effectively “withhold” or reduce the quantity of 

supply that is offered at “competitive” prices. 

Electronic trading platform: An electronic system that 

allows brokerages and individual traders to trade 

directly between themselves without having to go 

through a middleman.

Equity financing: Providing the necessary capital by selling 

common stock or preferred stock to investors. 

Exchange: A marketplace in which shares, options and 

futures on stocks, bonds, commodities and indices 

are traded.

Financial liquidity: An entity’s ability to obtain funds 

to meet its cash flow obligations, with consideration for the speed with which such funds can 

be obtained. 

Financial transmission right: A contract that entitles the 

holder to receive compensation (or pay) for certain 

transmission charges that arise when the grid is 

congested and differences in locational prices 

result from the redispatch of generators to relieve 

that congestion. 

Firm transportation: Contracted energy deliveries that are 

guaranteed not to be interrupted. 

Forward price curve: The chronological set of prices determined by a market for a good that will be delivered 

in the future. 

Fuel-adjustment clause: A provision of a power sales agreement or rate schedule that allows for the electricity 

price to be changed based on changes in the price 

of the fuel used to generate the power. 

Futures market: A market in which contracts for future 

delivery of a commodity are bought or sold. 

Heating degree days: A measure of heating energy demand 

determined by how far a location’s temperature 

averaged below 65 degrees Fahrenheit. 

Hedging: A risk management tool used to protect the value 

of an investment or contractual commitment from 

the risk of loss due to price fluctuations. 

Hirschman-Herfindahl Index (HHI): Often used 

to evaluate mergers, the HHI is a commonly 

accepted measure of market concentration. It is 

calculated by squaring the market share of each 

firm competing in a market, and then summing 

the resulting numbers. 

Hub: A geographical location where multiple participants 

trade services. 

Independent market monitor: A party that monitors 

market operations for compliance with market 

rules and identifies flaws in market rules or other 

issues affecting market efficiency and market 

power abuses. 

Independent system operator (ISO): An organization that 

has been granted the authority to operate, in a 

nondiscriminatory manner, the transmission assets 

of the participating transmission owners in a fixed 

geographic area. ISOs often run organized markets 

for spot electricity. 

Injection season: The April 1 through Oct. 31 period, 

during which gas is injected into natural gas 

storage reservoirs in preparation for withdrawal 

and use during the winter heating season. 

Interruptible or nonfirm transportation: Transmission 

service that is reserved and scheduled on an 

as-available basis and is subject to curtailment 

or interruption. 

Intertie: The point of physical interconnection between 

adjacent transmission systems. 

Load: Often synonymously used with demand, load is the 

total amount of power carried by an electric system 

at a point in time. 

Load pocket: An area isolated by the limits of the transmission network to get power into the area; demand 

within the load pocket exceeds internal generation, 

so imports are needed or reliability will fail. 

Load-serving entity (LSE): Any entity, including a load 

aggregator or power marketer, that serves endusers within a control area and has been granted 

the authority or has an obligation pursuant to 

state or local law, regulation or franchise to sell 

electric energy to end-users located within the 

control area. 

Locational marginal price: The market-clearing price for 

electricity at the location the energy is delivered 

or received. 

Long position: The market position of a futures contract 

buyer whose purchase obligates him to accept 

delivery unless he liquidates his contract with an 

offsetting sale. 
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130 

Loop flow: The fact that electricity flows on transmission 

lines in accord with the physical laws of electricity 

and not on the route contracted for by the seller. 

In some areas, system configuration is such that 

electricity flows in large cross-regional loops, as 

around the Great Lakes area of southern Canada. 

Losses: Energy (kilowatt-hours) and power (kilowatts) lost 

in the operation of an electric system. Losses occur 

principally as waste heat in electrical conductors 

and apparatus such as transformers. 

Margin requirement: The amount of money required to 

hold a contract and cover changes in the value of 

the contract. 

Marginal electric generating unit: The last unit turned on 

in an area to serve load. In organized wholesale 

markets, the price of the marginal source of 

electricity usually sets the price for all generation 

within the market. 

Mark-to-market: The process whereby the book value or 

collateral value of a security is adjusted to reflect 

current market value. 

Market capitalization: A measure of company size that is 

computed as current market price per share of 

stock times the total number of shares outstanding. 

Market liquidity: The ease, or lack thereof, with which a 

buyer can buy or a seller can sell at a prevailing 

price in a marketplace. 

Market monitoring unit: An independent and objective 

overseer of organized power markets. The MMU 

evaluates and reports on the operation of the 

markets, including transmission congestion costs 

and the potential for a market participant to 

exercise undue market power.

Market participant: A market buyer or a market seller, or 

both, that meets reasonable creditworthiness standards established by the market operator. 

Market power: A measure that can include, but is not 

limited to, the ability of a firm to raise its price or 

withhold its output with the effect of raising market 

prices above competitive levels for a sustained 

period of time. 

Merchant generator: A generating plant built “on spec,” 

with no energy sales contracts in place. Merchant 

plants compete in the deregulated market on their 

ability to generate low cost power and support the 

local grid system. 

Mitigation: A process by which a market operator can 

deter market behavior that may interfere with the 

competitive and efficient operation of the markets 

when market participant conduct falls outside 

certain prescribed guidelines. 

Native load: Wholesale and retail customers that the transmission provider has an obligation to serve. 

Open access: 1) A term becoming generally applied to the 

evolving access to the transmission system for all 

generators and wholesale customers. (2) The use of 

utility’s transmission and distribution facilities on a 

common-carrier basis at cost-based rates. 

Over the counter (OTC): Named for what was once an 

informally organized market, the OTC is today a 

well organized market place although with little 

or no regulatory oversight in comparison to an 

exchange or customized derivatives traded outside 

of an organized exchange.

Peaking capacity: Generating equipment normally operated 

only during the hours of highest daily, weekly, or 

seasonal loads; this equipment is usually designed 

to meet the portion of load that is above base load. 

Pivotal supplier: A power supplier whose capacity must be 

used to meet peak demand and whose capacity 

exceeds the market’s supply margin. 

Project financing: A form of asset-based financing in which 

a firm finances a discrete set of assets (the project) 

on a stand-alone basis. 

Ramp rate: The rate at which you can increase load on a 

power plant. The ramp rate for a hydroelectric 

facility may be dependent on how rapidly water 

surface elevation on the river changes. 

Real-time market: An electric market that determines 

the economic dispatch and establishes a marketclearing price for settlements for one-hour periods 

or less during the day of delivery. 

Real-time pricing: A system that provides signals to customers on the value of consuming energy at the time 

of consumption. 

Reference price: The settlement price of a derivatives 

contract, based on a particular location and 

commodity, or an estimated electricity price, based 

on a forecast of market conditions. 

Regional transmission organization (RTO): An organization with some similar roles to an independent 

system operator (ISO) but covering a larger 

geographical scale and involved in both operation 

and planning of the transmission system. RTOs 

often run organized markets for spot electricity.
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A P P E N D I C E S

Reliability must run (RMR): A unit identified by the ISO as 

necessary for operational or reliability reasons and 

must run, regardless of economic considerations. 

Reserve margin: The percentage of installed capacity 

exceeding the expected or actual peak demand 

during a specified period. 

Residual Supply Index (RSI): Residual supply is the 

amount of generation capacity remaining in the 

market, after subtracting the capacity of the largest 

supplier. If RSI exceeds 100 percent, this indicates 

that the alternative suppliers have sufficient 

capacity to meet demand without the largest 

supplier, who is thus presumed to have relatively 

little influence on the market-clearing price for 

a given hour. However, if the RSI is below 100 

percent, this indicates that the largest supplier’s 

capacity is needed to meet market demand and the 

supplier is considered pivotal in determining the 

market-clearing price for that hour. 

Retail unbundling: Disaggregating electric utility service 

into its basic functions and offering each component separately for sale with separate rates for each 

component. For example, generation, transmission 

and distribution could be unbundled and offered 

as discrete services. 

Ring-fencing: Techniques used to isolate the credit risk of a 

subsidiary within a corporation from the risk of its 

affiliated companies. 

Risk management: The process of analyzing exposure 

to risk and determining how to best handle 

such exposure. 

Seams: Barriers and inefficiencies resulting from equipment limitations and differences in market rules 

and designs, operating and scheduling protocols 

and other control-area practices that inhibit 

or preclude the ability to transact capacity and 

energy between regions. 

Short position: The market position of a futures contract 

seller whose sale obligates him to deliver the 

commodity unless he liquidates his contract by an 

offsetting purchase. 

Single settlement system: A market structure that provides 

only a real-time market. 

Spark spread: The cost difference of converting natural 

gas into electricity. It can also be the difference 

between gas and electricity futures prices. 

Marketers use the spark spread as an indicator of 

arbitrage opportunities. 

Spot market: The natural gas market for contractual 

commitments that are short term (usually a 

month or less) and that begin in the near future 

(often the next day, or within days). In electricity, spot markets are markets for day-ahead 

and real-time electricity, sometimes run by an 

independent system operator or regional transmission organization.

Spread trading: Buying one instrument/commodity and 

selling another, with a view to profiting from the 

change in the gap between the two markets.

Swaps: An exchange of streams of payments over time 

according to specified terms. An example of a 

natural gas fixed-for-floating swap is to swap 

a fixed price for natural gas against a specified 

index price at a defined geographical point over a 

specified time period. 

Time-of-use pricing: A rate design imposing higher charges 

to customers during periods of the day when 

higher demand and higher cost of production is 

experienced. 

Tolling agreement: An agreement whereby a party moves 

fuel to a power generator and receives kilowatt 

hours (kWh) in return for pre-established fees.

Transaction costs: Costs incurred when buying or selling 

assets, such as commissions and the spread.

Transmission loading relief (TLR): A situation called 

when electricity flows exceed permitted levels; 

a TLR is called to preserve the reliability of the 

electric transmission system. A TLR interrupts 

specific transmission flows or transactions and 

may curtail service to specific customers or future 

transmission schedules.

Transparency: A measure of the extent to which a market’s 

current trade and quote information is readily 

available to the public.

Two-settlement system: A system under which the price 

for electricity on any given day is established both 

on a day-ahead and a real time basis. Day-ahead 

prices are based on forecasted energy demand and 

transmission and generation availability. Real-time 

prices reflect not only the day-ahead anticipated 

events and unit schedules, but also what actually 

occurs in real time, such as generation or transmission outages, and changes in forecasted load.

Uplift: Uplift generally refers to costs allocated to all market 

participants in a given region or market and not 

charged directly to the participant that caused the 

cost to be incurred. Some categories of charges 
O F F I C E O F M A R K E T O V E R S I G H T A N D I N V E S T I G A T I O N S

132 

that may be allocated to uplift are ancillary services 

and out-of-merit dispatch costs.

Usage charge: A broad term which refers to charges levied 

on power suppliers or their customers for the use 

of the transmission or distribution wires.

Virtual bidding: A practice that allows participants to hedge 

against the risk that real-time and day-ahead prices 

will differ, or to speculate on the difference.

Voice broker: A trading intermediary matching buyers and 

sellers using the approach of telephone confirmation, versus an electronic trading platform.

Volatility: A measure of the price fluctuation of a commodity or financial instrument that takes place over a 

certain period of time.

Volumetric risk: The effect on revenue of fluctuations in 

demand for a product or service.

Wash trade: A prearranged pair of trades of the same good 

between the same parties, involving no economic 

risk and no net change in beneficial ownership. 

Wholesale electricity markets: The purchase and sale of 

electricity from generators to resellers (who sell to 

retail customers) along with the ancillary services 

needed to maintain reliability and power quality at 

the transmission level.

Winter heating season: The Nov. 1 through March 31 

period, during which most natural gas use for 

space heating takes place.

Zonal price: A pricing mechanism for a specific zone within 

a control area. 
133

A P P E N D I C E S

LIST OF FIGURES AND

TABLES Appendix 9:

Figures

Figure 1: Market events challenge natural gas/power market liquidity and credibility. . . . . . . . . . . . . . . . . . . . . . . 4

Figure 2: Operating or forming organized electricity markets serve approximately 70 percent of U.S. population. . . . . . . 6

Figure 3: Generation ownership concentration lower in organized markets. . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

Figure 4: Natural Gas is the marginal fuel in many regions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10

Figure 5: Monthly natural gas prices peak in late-winter 2002 and remain high through following summer. . . . . . . . . .12

Figure 6: Storage use pushes upper and lower capacity limits. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .13

Figure 7: 2003 producer drilling response to high prices is moderate. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Figure 8: Map of electricity regions assessed. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18

Figure 9: Physical and financial power markets work efficiently in tandem. . . . . . . . . . . . . . . . . . . . . . . . . . . .20

Figure 10: Regions in organized markets tended to have low shares of indigenous low-cost generation resources. . . . . . .21

Figure 11: Cinergy electricity trading on ICE reaches Henry Hub gas liquidity. . . . . . . . . . . . . . . . . . . . . . . . . . .23

Figure 12: Capacity market share lower in organized markets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .24

Figure 13: Multiple companies own New England generation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .25

Figure 14: New York peaking generation concentration high. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .25

Figure 15: High generation ownership shares in regions without organized electricity markets. . . . . . . . . . . . . . . . .26

Figure 16: Southern subregion of SERC generation ownership concentrated. . . . . . . . . . . . . . . . . . . . . . . . . . .27

Figure 17: Organized market power prices generally lower and more stable than in 2001. . . . . . . . . . . . . . . . . . . .29

Figure 18: Organized market volatility declines. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .30

Figure 19: Reported bilateral trading volumes in organized markets decline. . . . . . . . . . . . . . . . . . . . . . . . . . .32

Figure 20: ISO-NE prices increase. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .35
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Figure 21: NYISO average monthly prices increase. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .37

Figure 22: NYISO day-ahead volatility peaks in summer 2002. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .38

Figure 23: Summer PJM prices sensitive to peak load. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .40

Figure 24: PJM real-time prices highly volatile. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .40

Figure 25: California’s real-time energy market is a small part of total market. . . . . . . . . . . . . . . . . . . . . . . . . . .42

Figure 26: Regions without organized markets have prices generally lower than in 2001, though spikes occur. . . . . . . . .44

Figure 27: Price volatility increases in most regions without organized markets. . . . . . . . . . . . . . . . . . . . . . . . . .46

Figure 28: Reported trading volumes decline in regions without organized markets. . . . . . . . . . . . . . . . . . . . . . .47

Figure 29: TLR activity increases in most regions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .48

Figure 30: Entergy electricity prices correlate with natural gas prices. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .49

Figure 31: Midwestern power price spike may make gas-fired units competitive. . . . . . . . . . . . . . . . . . . . . . . . .50

Figure 32: Map of NERC control areas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .54

Figure 33: Inter-regional power price differentials vary. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .57

Figure 34: New England-New York price differential narrows. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .58

Figure 35: Gas scheduling and power bidding timelines vary. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .59

Figure 36: Power price volatility tops all major commodities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .59

Figure 37: PJM futures volume and open interest increase. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

Figure 38: PJM futures prices follow seasonal patterns. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .62

Figure 39: New additions increase U.S. capacity by 10 percent. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .65

Figure 40: New York City demand response is cost-effective. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .71

Figure 41: Energy company credit ratings deteriorate before and during the assessment period. . . . . . . . . . . . . . . . .75

Figure 42: Regional North American natural gas markets are connected by pipeline and related infrastructure. . . . . . . .78

Figure 43: Monthly natural gas prices peak in late-winter 2002 and remain high through following summer. . . . . . . . . .79

Figure 44: Natural gas futures prices reach new levels. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .80

Figure 45: Overall consumption declines in first half of 2003, but residential and commercial demand increases. . . . . . .81

Figure 46: Decline rates increase. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .82

Figure 47: Production versus storage withdrawal gap widens in February 2003. . . . . . . . . . . . . . . . . . . . . . . . . .82

Figure 48: Relationship strong between storage level and price. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .83

Figure 49: Storage use pushes upper and lower capacity limits. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .83

Figure 50: Pipeline capacity generally adequate for much of the year. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .84

Figure 51: New infrastructure affects Rocky Mountain basis differentials. . . . . . . . . . . . . . . . . . . . . . . . . . . . .85

Figure 52: Many customers choose to weather short basis blowouts rather than pay for pipeline additions. . . . . . . . . . .85

Figure 53: Henry Hub price volatility increases from the 1990s. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .86

Figure 54: Winter 2002–03 cost of gas in storage lower than cash market prices. . . . . . . . . . . . . . . . . . . . . . . . .87

Figure 55: Next-day Henry Hub spot prices move in the same direction as next-month futures prices. . . . . . . . . . . . .88

Figure 56: Nymex natural gas futures volumes trend upward. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .88

Figure 57: Nymex open-interest decline points to less forward participation. . . . . . . . . . . . . . . . . . . . . . . . . . .89

Figure 58: Henry Hub volumes reported to index publishers decline in mid-2002. . . . . . . . . . . . . . . . . . . . . . . .90

Figure 59: Transco Zone 6-NY volumes reported to index publishers decline in mid-2002. . . . . . . . . . . . . . . . . . . .91

Figure 60: The number of counterparties transacting next-day trades varies by location. . . . . . . . . . . . . . . . . . . . .92

Figure 61: In 2003, forward price expectations shift upward. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .94
135

A P P E N D I C E S

Figure 62: 2003 producer drilling response to high prices moderate. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .95

Figure 63: More drilling needed to maintain production. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .95

Figure 64: Map and output capacities of existing and proposed LNG terminals. . . . . . . . . . . . . . . . . . . . . . . . . .96

Figure 65: FERC certifications signal new pipeline investments. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .98

Figure 66: New pipeline firm subscribers mostly power generation shippers. . . . . . . . . . . . . . . . . . . . . . . . . . .99

Figure 67: New Rockies investment still justified by basis differentials. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100

Figure 68: Projected Henry Hub to Transco Zone 6-NY basis does not support new construction. . . . . . . . . . . . . . . 101

Figure 69: Map of ISO-NE. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103

Figure 70: Map of NYISO. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104

Figure 71: Map of PJM. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104

Figure 72: Map of the Southeast. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 105

Figure 73: Map of Florida. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 105

Figure 74: Map of the Midwest. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106

Figure 75: Map of South Central. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106

Figure 76: Map of ERCOT. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107

Figure 77: Map of the Southwest. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107

Figure 78: Map of the Northwest. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 108

Figure 79: Map of CAISO. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 108

Figure 80: Generation ownership concentration in ISO-NE. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111

Figure 81: Generation ownership concentration in NYISO. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112

Figure 82: Generation ownership concentration in PJM. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112

Figure 83: Generation ownership concentration in ERCOT. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112

Figure 84: Generation ownership concentration in CAISO. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 113

Figure 85: Generation ownership concentration in the Southeast (Southern). . . . . . . . . . . . . . . . . . . . . . . . . . 113

Figure 86: Generation ownership concentration in the Southeast (Entergy). . . . . . . . . . . . . . . . . . . . . . . . . . . 113

Figure 87: Generation ownership concentration in the Southeast (VACAR). . . . . . . . . . . . . . . . . . . . . . . . . . . 114

Figure 88: Generation ownership concentration in the Southeast (TVA). . . . . . . . . . . . . . . . . . . . . . . . . . . . . 114

Figure 89: Generation ownership concentration in Florida (FRCC). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 114

Figure 90: Generation ownership concentration in the Midwest (ECAR). . . . . . . . . . . . . . . . . . . . . . . . . . . . . 115

Figure 91: Generation ownership concentration in the Midwest (MAIN). . . . . . . . . . . . . . . . . . . . . . . . . . . . . 115

Figure 92: Generation ownership concentration in the Midwest (MAPP). . . . . . . . . . . . . . . . . . . . . . . . . . . . . 115

Figure 93: Generation ownership concentration in South Central (SPP). . . . . . . . . . . . . . . . . . . . . . . . . . . . . 116

Figure 94: Generation ownership concentration in the Southwest (RMPA). . . . . . . . . . . . . . . . . . . . . . . . . . . 116

Figure 95: Generation ownership concentration in the Southwest (AZ-NM-SNV). . . . . . . . . . . . . . . . . . . . . . . . 116

Figure 96: Generation ownership concentration in the Northwest (NWPP). . . . . . . . . . . . . . . . . . . . . . . . . . . 117

Figure 97: Overall electricity generation variable but continues to rise. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 121

Figure 98: Recent increases in coal and petroleum fuel use offset declines in gas use. . . . . . . . . . . . . . . . . . . . . 121

Figure 99: Approximate locations of gas and electric price points. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123
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Tables

Table 1: Wholesale energy markets design, June 2003. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Table 2: Wholesale electric market products. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Table 3: Number of wholesale buyers and sellers in organized markets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .22

Table 4: Electricity volumes transacted in organized markets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .22

Table 5: Reported electricity volumes transacted bilaterally. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .23

Table 6: Electricity prices in regions with organized electricity markets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .30

Table 7: Electricity volumes transacted in organized markets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Table 8: Reported bilateral trading volumes in regions with organized markets. . . . . . . . . . . . . . . . . . . . . . . . . .32

Table 9: Mitigation procedures by region. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .34

Table 10: Congestion cost components in ISO-NE zones. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .36

Table 11: Prices in regions without organized electricity markets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .45

Table 12: Reported trading volumes in regions without organized electricity markets. . . . . . . . . . . . . . . . . . . . . .46

Table 13: Short-term and long-term contracting by region. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .52

Table 14: Selected design elements of energy markets, June 2003. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .55

Table 15: Design elements of FTR markets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .64

Table 16: Profitability indicated for CAISO and NYISO investment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

Table 17: Investment not signaled in regions without organized markets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

Table 18: Net revenue tests suggest investment in New York City, Long Island and Delmarva load pockets. . . . . . . . . . .69

Table 19: Demand response cost effective in some key locations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .71

Table 20: Merchant transmission projects. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .72

Table 21: Storage capacity control shares by category of users. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .97

Table 22: Generating capacity additions and reserve margins. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109
S T A T E O F T H E M A R K E T S

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ACKNOWLEDGEMENTS

T

eam leaders for this report were David Behrman, Alan Haymes, Lance Hinrichs, Steven Michals, 

Patricia Morris, Christopher Peterson, Mary Beth Tighe, Julia Tuzun and Dean Wight. Significant 

analysis and assistance was provided by Stacy Angel, Darrell Blakeway, Bill Booth, James Caruso, Mary 

Evans, Jolanka V. Fisher, Robert Flanders, Sidney Givens, Jesse Halpern, Christie So Kim, Kenneth 

Kohut, Rafael Martinez, Michael P. McLaughlin, William Meroney, Lisa Carter Moerner, Jennifer Morgan, Kara 

Mucha, Thomas Pinkston, Clint Ramdath, Michelle Reaux, Steve Reich, Thomas Rieley, Harry Singh, Stephen 

Surina, Sebastian Tiger, Jo Tolley, Rahul Varma, Carol Brotman White and Young Yoo. In addition, significant 

assistance was provided by Meesha Bond, Ray James, Camilla Ng, John Schnagl and Jeff Wright in FERC’s Office 

of Energy Projects and Jerome Pederson and Steve Rodgers in FERC’s Office of Markets, Tariffs and Rates. Ann 

Vanture was the report’s graphic designer. John Jennrich and Scott Speaker were the report’s copyeditors.
EVALUATION FORM: 

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