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State of the Markets Report • June 2005 1

A Staff Report by theOffice of Market Oversight and Investigations

Federal Energy Regulatory Commission

Published June 2005 • Docket MO05-4-000

2004

STATE OF THE MARKETS REPORT

An Assessment of Energy Markets in the United States in 2004
2 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

State of the Markets Report

PREFACE

This is the Federal Energy Regulatory Commission’s third State of the Markets Report. 

Produced by the Commission’s Office of Market Oversight and Investigations (OMOI), 

the report covers electric, natural gas, and other related energy market activity during 2004. 

In contrast to seasonal assessments, which focus on the near future, this report examines 

performance in the recent past. The State of the Markets Report presents findings regarding 

market conditions relevant to the Commission and identifies emerging trends 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 efforts of OMOI staff for this project. 

Major contributors to this team effort are listed in the Acknowledgments.

A fair energy market 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

We encourage readers to provide feedback on this report by

filling out the State of the Markets Report Evaluation Card 

at the end of the report, sending comments in an e-mail to

SOM.2004@FERC.gov, or by contacting staff referenced in the

acknowledgments by mail or phone.

OMOI (State of the Markets Report)

FERC 

888 First Street, N.E.

Washington, D.C. 20426

202-502-8100
Executive Summary 5

2004 Issues in Energy Markets

Markets Under Stress: New England Reacts to Record Cold 13

Electric Market Investment and Merger Trends 25

Energy Market Information 35

Market Behavior Rules: Effectiveness Review 45

Electric Power Market Profiles 

National Overview 49

California (CAISO) 69

Midwest (MISO) 77

New England (ISO–NE) 83

New York (NYISO) 91

Northwest 99

PJM 105

Southeast 115

Southwest 121

Southwest Power Pool (SPP) 127

Texas (ERCOT) 131

Natural Gas Market Profiles 

National Overview 137

Natural Gas Trading 151

Midwest 157

Northeast 165

South Central 175

Southeast 185

Western 193

Other Related Markets and Market Factors

Overview 203

Coal 205

Demand Response 211

Emission Allowances 215

Energy Debt and Equity 221

Oil 225

Weather 229

Wind 231

Other Material

Glossary • Acronyms 237

Analytic Note on Net Revenue Calculations 247

Acknowledgments • Contacts 249

Evaluation Form 253

State of the Markets Report • June 2005 3

State of the Markets Report

TABLE OF CONTENTS
4 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations
I

n 2004, U.S. natural gas and electric markets responded

to broad upward price pressure as connections among

energy markets became tighter. In New England in

January, for example, a short, severe cold snap pushed

the operational connections between natural gas and

electric markets to the limit. During the year, financial

energy markets expanded as many participants found it

easier to enter the financial markets than the associated

physical natural gas and electric markets. Global influences on U.S. energy markets manifested themselves in

the form of higher oil prices and (early in 2005) in an

early but developing North Atlantic spot market for 

natural gas.

Pricing

World oil prices rose 34 percent in 2004. This created

upward pressure on many energy commodity prices globally and affected energy markets in the United States. For

example,

• Average U.S. natural gas prices rose 7 percent nationally

from 2003 to 2004, following a rise of 68 percent from

2002 to 2003. Regional patterns persisted. Natural gas

prices were relatively higher in the Northeast and lower

in the West.

• Spot coal prices rose 69 percent for eastern (central

Appalachian) coal, and 7 percent for western (Powder

State of the Markets Report • June 2005 5

Executive Summary

EXECUTIVE SUMMARY

$0

$40

$80

$120

$160

$200

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Range of Day-Ahead On-Peak Power Prices ($/MWh) 

$0

$4

$8

$12

$16

$20

Henry Hub Natural Gas Prices ($/MMBtu)

1/15/04: $315

1/14-16: New England cold snap 

 puts stress on gas and electric systems

5/1: ComEd integrates into PJM

5/1: NYISO refines NYC mitigation

8/1: Platts and NGI start reporting number 

 of trades and volumes for monthly gas indices

9/16: Hurricane Ivan makes landfall

10/1: SPP receives regional transmission organization status

10/1: AEPS and Dayton Light & Power integrate into PJM; 

 Illinois Power integrates into MISO

10/1: CAISO begins real-time economic dispat

10/4: U.S. renews Federal production tax credit for wind 

11/4: Volume of working gas in storage hits all-time high of 3,322 Bcf

11/24: EIA misreports gas storage withdrawals

12/20: Exelon/PSEG announces merger 

12/28: FERC approves NYISO 

 realiabiltity planning process

1/1/05: Duquesne integrates into PJM

1/20: FERC/MMU common metrics agreement

2/27:Transmission auction to New York City fails (Conjunction)

3/10: Industry coalition announces confidence in natural gas price indices

2/12: Nymex launches PJM option

9/8: California reaches new peak load record

 for seventh time during year

State of the Markets Timeline: 2004
6 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

River Basin) coal. Spot coal prices can influence electric

power prices significantly, because marginal generators

can choose to sell the coal or burn it to sell power.

Because large quantities of coal are purchased under

long-term contracts with specified prices, overall average prices for coal rose only 6 percent. 

• Sulphur dioxide (SO2) emissions allowance prices rose

by 153 percent in 2004. SO2 allowances were a major

input for coal-fired plants without scrubbers, adding as

much as $17.40 per MWh to a plant’s cost.

Electricity prices followed the pattern set by fuel and emissions prices.

• In most regions where natural gas tended to be on the

margin (e.g., New England, New York, Texas, and for

on-peak hours at PJM West) prices increased by less than

5 percent. Florida and California both depended heavily on natural gas, and their price increases were 8 to 12

percent on peak—higher than for other gas-dependent

areas.

• In areas where western coal tended to be on the margin

(e.g., the Southwest and Great Plains), on-peak price

increases were less than 6 percent. 

• Where eastern coal (and associated emissions

allowances) tended to be on the margin, prices rose

more. In the Southeast and the Midwest, on-peak

power prices rose by 11 to 19 percent. Off-peak prices in

these regions increased even more, as much as 33 percent. Similarly, at PJM West, where coal was more often

on the margin during off-peak hours, the average offpeak price increase was 25 percent.

RTO markets continued to administratively adjust prices,

especially in reaction to market power concerns in 

constrained areas.

Weather and Its Effects on Markets

Weather put little stress on energy markets during most of

the year. The winter of 2003–2004 was 6 percent warmer

than the previous winter, and the summer of 2004 was the

ninth coolest on record. There were two major exceptions

to this pattern.

• A cold snap in New England in January 2004 underscored the importance of tight integration between the

gas and electric markets during periods of stress.

Although the two markets successfully responded to the

severe weather, both industries subsequently analyzed

the event to learn how they could coordinate better in

the future. 

• Hurricane Ivan hit producing regions of the Gulf Coast

in September, reducing overall gas production in the

United States by almost 1 percent. This probably contributed to a price increase in October.

Investment

As a whole, the U.S. electric industry had significant overcapacity in generation in 2004. Appropriately, the markets

signaled no need for new capacity nationally. At the same

time, specific constrained regions did not have adequate

capacity. These areas included Boston, southwest

Connecticut, New York City, New Orleans, much of southern California, and the San Francisco Bay Area. Most of

these areas also saw prices too low to signal new investment.

• In regions without location-specific pricing, price 

signals cannot distinguish between areas that need

capacity and those that do not. Such regions include

those outside regional transmission organizations

(RTOs); areas within RTOs that do not yet have RTOmanaged spot markets (Southwest Power Pool—SPP—

and the Midwest Independent System Operator—

MISO—in 2004); and zones within RTOs with zonal

pricing (California and Texas).

• In New England, the independent system operator

(ISO-NE) took many generators “out of market” and

required them to run for reliability reasons, reducing

price signals. The practice of pricing generators individually was so common that almost no difference existed

between the market prices that ISO-NE published for

energy in areas that were constrained versus those without constraints. 

• New York City prices were high enough to make investment marginally attractive under best-case assumptions.

In practice, much of the new capacity coming on line in

the city was being built by a state agency.

Executive Summary
• Southern California prices would have provided about

two-thirds of the revenue needed to justify investment,

despite widespread concerns about the adequacy of

reserves going into the next summer (2005).

In transmission, investment increased for the fourth year

in a row; up 69 percent since 2001. At the same time, few

new high-voltage lines came on line—931 circuit miles

nationally—compared with an overall system of more than

150,000 circuit miles. 

The natural gas industry has responded to price signals

effectively for decades. Expenditures on exploration and

production were up 45 percent from the average of 2001

and 2002. The industry continued adjusting its pipeline

and storage infrastructure in 2004. Total expenditures

were lower than in 2003, mostly because there were few

projects to increase long-haul pipeline capacity after completion of the Kern River expansion in 2003. 

Regional Issues

Electric power remained an essentially regional commodity,

with markets that reflected regional institutions. About

two-thirds of the country (as a share of gross domestic

product) had adopted RTO models for organizing markets.

In 2004, SPP formed an RTO, MISO advanced toward successfully implementing full RTO markets in 2005, and

ISO-NE filed to become an RTO. Other RTOs continued

to develop their markets. 

The West (except California) and the Southeast constituted

two broad regions without RTOs. In the West, bilateral

markets have existed for years, and price quotations were

available from liquid trading points in both the Northwest

(mid-Columbia and the California-Oregon Border) and

the Southwest (Palo Verde, Four Corners, and Mead). In

the Southeast, markets were largely opaque—only the

“Into Entergy” pricing point provided published prices

State of the Markets Report • June 2005 7

Executive Summary

Electric Regions with Pricing Nodes On-Peak Prices ($/MWh)

Northwest

California

Southwest

Midwest

SPP

ERCOT

Southeast

PJM

New York

New England

Prices 2004

Prices 2003Prices 2003

Percentage change

Mid-Columbia

$44.54

$40.73

9.3%

COB

$49.09

$44.49

10.3%

$54.46

$49.13

10.9% NP-15

SP-15

$55.20

$51.25

7.7%

$51.91

$50.65

2.5 %

Mead

$50.09

$49.10

2.0%

Palo Verde

$47.32

$46.49

1.8%

ERCOT

$50.51

$48.55

4.0%

Four Corners

$45.19

$41.66

8.5% SPP

$45.90

$43.29

6.0%

MAPP S

$47.06

$45.18

4.2%

MAPP N $47.94

$43.14

11.1%

MAIN N

$42.03

$37.11

13.2% NI Hub

$45.76

$41.47

10.3%

Entergy

$44.23

$38.90

13.7%

TVA

$58.31

$52.21

11.7%

Florida

$48.67

$41.55

17.1%

Southern

$43.31

$37.57

15.3%

Cinergy

$51.10

$48.49

5.4% PJM West

$45.58

$38.41

18.7%

ECAR N

$52.49

$51.36

2.2%

$61.74

$61.73

0.0%

$61.47

$59.05

4.1% NYISO A

NYISO G

Mass Hub

$76.63

$77.82

-1.5%

NYISO J

$48.27

$41.60

16.0%

VACAR

MAIN S

$42.85

$38.43

11.5%
8 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

with reasonably high levels of liquidity. Elsewhere, published price indices relied on few trades or substituted analytic judgment for reports of real trades.

A continental market for natural gas has existed in North

America for at least 15 years. In addition, a global long-term

contract market for liquefied natural gas (LNG) has been

growing. Entering 2005, there appears to be an emerging

North Atlantic spotmarket for gas as well. During February

and March, Western Europe experienced a natural gas

price spike. When LNG cargoes stopped arriving at Lake

Charles, reports followed that some cargoes had been

diverted to Europe—just as had happened in reverse in

recent years.

Financial Markets

The financial aspects of energy markets became more

important in 2004.

Nontraditional buyers (mostly private equity and lenders

to distressed assets) acquired almost 30 GW of generation

in 2004, close to 5 percent of total capacity in the United

States and more than five times as much capacity as in

2003.

Financial trading on the IntercontinentalExchange (ICE)

rose by a factor of 10 for electric power. Although ICE represented only a fraction of all financial trading, the increase

Executive Summary

2004 Locational Natural Gas Prices

El Paso

Permian

$5.34

$0.28 Pricing Point

Current Price

1-year price differential

This year - last year

Basis

NW Sumas

$5.15

$0.46

Malin

$5.35

$0.45

PG&E

Citygate

$5.75

$0.52

SoCal Border

$5.51

$0.43

El Paso

San Juan

$5.18

$0.62

Kern River

Opal

$5.19

$0.88

AECO Hub

$5.04

$0.33

Waha Hub

$5.38

$0.21

Panhandle

Tex-Okla

$5.45

$0.28

Katy Hub

$5.67

$0.31

Tennessee 

Zone 0

$5.64

$0.38

Henry Hub $5.85

$0.41

Tetco M-1

$5.93

$0.38

Chicago

Citygate

$5.85

$0.30

Dawn

$6.08

$0.30

Niagara

$6.20

$0.26 Algonquin

Citygate

$6.86

$0.34

Transco

Zone 6 - NY

$6.81

$0.36

Columbia 

Pool

$6.14

$0.45

$0.31

$0.04

$0.32

$0.33

$0.16

$0.13

$0.29

$0.03

$0.40

$0.27

$0.81

$0.23

$0.12

$0.67

$0.05

$0.96 $0.00

$0.96

$0.18

$0.20

$0.39

$0.24
appeared to signal a significant increase in overall financial

trading of energy. This uptick was consistent with anecdotal reports of increasing hedge fund activity in energy markets. The effect of this trading on physical energy prices

was not yet clear.

In natural gas markets, physical and financial market prices

converged for most of the year. The exception was a period

during the fall when physical prices dropped because storage was full.

During 2004, financial market players significantly

improved the efficiency with which companies could

address credit risk. Clearing arrangements let companies

net out their positions and deal with a single platform

instead of having to establish separate credit requirements

for each customer.

Information

Energy markets depend on reliable information about

prices and basic demand and supply conditions. In 2004,

confidence in energy price indices improved, but the natural gas industry remained vulnerable to a lack of information about current supply and demand.

In the aftermath of the western energy crisis of 2000–01,

confidence faltered in energy markets in general and price

indices in particular. To address the situation, in 2003 and

2004, the Commission encouraged industry to improve the

index reporting process. By 2004, reporting companies had

better procedures in place to ensure accurate reports to

index publishers. Index publishers in turn reported far

more details about the indices (such as the number of 

transactions and total volumes reported for a given price).

The Commission laid out requirements for indices to be

included in jurisdictional contracts, and many market 

participants expressed greater confidence in using them.

Nonetheless, a rising price environment challenged the

new confidence, and pricing mechanisms remained under

close scrutiny by policy makers in Congress and elsewhere. 

Timely natural gas supply information remained scarce. In

its absence, the Energy Information Administration (EIA)

storage estimate is the best available indicator of the overall

balance of supply and demand—even though it represents

a tiny proportion of gas being produced or consumed at any

given time. Late in November, one company’s clerical

error led EIA to underestimate storage injections for the

previous week. During the rest of the trading day, gas

prices rose by 15 percent. Because the reporting day happened also to mark the close of the Nymex December

futures contract and bid week for monthly physical deliveries in December, the overall effects on the market were

large.

Guide to This Report

The report has four further sections: 

• Essays. Analysis of four topics relevant to the energy

markets in 2004.

• Electric Power Markets. An overview and 10 detailed

regional profiles of electric power markets around the

country. The overview includes a short guide to the content of the regional profiles.

• Natural Gas Markets. An overview, a profile of national financial trading for natural gas, and five detailed

regional profiles. The overview includes a short guide to

the content of the regional profiles.

• Other Related Markets and Market Factors. Profiles of

other markets related to natural gas and electric power

markets, including coal, emissions trading, oil, petroleum, uranium, and wind; plus a review of 2004 weather.

We offer the State of the Markets Report as a resource for

interested policy makers, energy customers, suppliers,

traders, and interested members of the general public. We

have written this report so that a reader can go directly to

subjects of interest, as necessary.

State of the Markets Report • June 2005 9

Executive Summary
10 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations
2004 ISSUES IN ENERGY MARKETS

State of the Markets Report • June 2005 11

This State of the Markets Reportcontains 4 essays: Markets Under Stress: New England Reacts to

Record Cold, Electric Market Investment and Merger Trends, Energy Market Information, and

Market Behavior Rules: Effectiveness Review.
12 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Other Related Markets and Market Factors

OVERVIEW

Each essay considers a key issue affecting natural gas and electric markets in 2004:

Markets Under Stress: New England Reacts to Record Cold. On January 15 and 16, 2004, New England

faced its coldest weather since 1943. Both natural gas and electric markets responded successfully to the cold weather. However, the stresses of meeting demand for both natural gas and electric power during the cold snap showed the

need for greater coordination between the two industries in the future. 

Electric Market Investment and Merger Trends Investment was a central issue for the electric industry in

2004. Investment in transmission rose in dollar terms, but remained much lower than investment in generation and

few high-voltage lines were added. Price signals to build generation were appropriately low in most of the country

(which has ample generating capacity). Private equity, hedge funds and lenders acquired almost five percent of the

nation’s generating capacity.

Energy Market Information. In modern markets, information is essential for market participants of all kinds.

During 2004, natural gas and electric industries improved the quality of published price indices by improving the

quality of the information reported to index publishers and by publishing more information about published prices.

The Commission improved reporting on its Electronic Quarterly Report of jurisdictional transactions. An error in EIA’s

natural gas storage reporting (due to a clerical error in one company’s submission) made clear the importance of accurate, timely information. The error led to a 15 percent increase in price during one day in November and affected

many related, longer-term natural gas markets.

Market Behavior Rules: Effectiveness Review. This essay reviews the effectiveness of the Commission’s

market behavior rules during their first full year in operation.
MARKETS UNDER STRESS:

NEW ENGLAND REACTS TO RECORD COLD

State of the Markets Report • June 2005 13

The interaction of market forces and electric grid

administration met the simultaneous needs for natural

gas distribution and electric generation despite significant strains in market operations. The experience was a

valuable one for gaining insight into how energy 

markets more generally perform under stress.

The normally tight supply/demand balance for 

natural gas in New England became critical when

demand spiked and imports declined during the cold

wave. High demand in eastern Canada, in the grip 

of the same cold weather, coupled with recent 

production declines in the Canadian Maritimes

reduced natural gas deliveries below pipeline capacity.

The tight gas supply situation made gas-fired generation

problematic.

On January 15–16, Boston faced its coldest successive two-day period since

1943 in what would become New England’s eleventh coldest month on

record.1 The extreme weather put simultaneous stresses on both electric and

natural gas systems, stresses that were resolved by redistribution of

spot gas supply at record high prices between heating and power loads.

State of the Markets Report • June 2005 13
14 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

New England has become increasingly dependent on natural gas-fired generation. Developers have installed more

than 10,000 MW of natural gas-fired generation capacity

since 1999. From January 14 to 16, New England electric

grid operator ISO-NE experienced a peak load of 22,800

MW—substantially below the total winter capacity of 32,640

MW. Much of New England’s natural gas-fired capacity

relies on the spot market for supply. When heating demand

increased with the extreme cold, spot natural gas availability dropped and prices spiked. On January 14, 7,073 MW of

natural gas-fired generation (53 percent) was out of service,

largely because of a lack of fuel. These outages resulted, in

part, from electric price signals that failed to attract spot 

natural gas to electric generation. 

As a consequence, some generators with firm natural gas

contracts sold their supplies on the spot market rather than

produce power. Resulting high outage levels caused an 

electric reserve deficiency, prompting ISO-NE to urge 

conservation and issue a potential blackout warning.

System stability was restored when several natural gas units

returned to service at ISO direction. Warmer weather

ultimately ended the crisis.

For the most part, energy markets did an effective job of

handling the simultaneous, competing demands on natural

gas for heating and electric generation.2 In particular:

• The natural gas spot market appropriately rationed supply to the highest-value users – to the heating load.

• Regional gas was legitimately in short supply due to

pipeline capacity limitations and import supply declines.

• Natural gas sales by electric generators during the cold

snap were allowed by ISO-NE rules and were economically rational because the power market cleared at a price

below the marginal cost of generating with natural gas.

• Electric prices cleared below marginal cost largely due to

ISO-NE day-ahead market operation and reliability unit

commitment practices, even though natural gas-fired 

generation was critically needed.

• Depending on natural gas units that may not have firm

fuel supply commitments for reliability reserves when

pipeline operations are constrained may overstate realistic

available reserve margins.

New England Gas Market Conditions

Although the cold wave spread over the eastern United

States and Canada, the most extreme cold weather was concentrated in New England and the eastern Canadian

provinces.

For January 14, Platts Gas Daily reported 79,000 MMBtu

traded for next-day natural gas delivery, less than half of the

167,000 MMBtu reported on January 9. Figure 1 shows the

daily prices and trading volumes for the Algonquin citygate

for January 2004.3 Colder weather and reduced supplies

pushed next-day spot prices on January 14 to a record New

England price of $63.42/MMBtu. Trades ranged from as

low as $38 to as high as $75/MMBtu. Prices on the

IntercontinentalExchange (ICE) declined at all trading

points except New England and New York. 

Interstate Pipeline Operations

Natural gas pipelines serving New England include

Algonquin Gas Transmission, Texas Eastern (which ends in

New Jersey, but supplies most of the gas delivered in New

England through Algonquin), Iroquois Gas Transmission,

Tennessee Gas Pipeline, Portland Natural Gas

Transmission, and Maritimes and Northeast (see Figure 2).

Markets Under Stress: New England Reacts to Record Cold

0

10

20

30

40

50

60

70

1/1/04 1/6/04 1/11/04 1/16/04 1/21/04 1/26/04 1/31/04

Gas Price ($/MMBtu) 

0

50

100

150

200

250

Trading Volume

$ per MMBtu

Trading Volume on ICE

Source: Derived from Platts Gas Daily data from January 14-16, 2004.

Fig 1: NE Gas Price Spike 
Transco, also shown on the map, primarily serves New York

City but can reflect price effects from New England. 

On January 14, Algonquin, Texas Eastern, Tennessee, and

Transco made use of much of their capacity, reaching load

factors ranging from 92 to 99 percent. Average capacity use

for the region was 92 percent, due to less use of Iroquois (73

percent), Portland (89 percent), and Maritimes (75 percent).

Overall regional capacity use averaged 99 percent on January

15 and 96 percent on January 16. 

Average regional use was lower on January 14 because of

capacity constraints on the eastern side of the TransCanada

system. Natural gas exports by a regional marketer fulfilling

a peak-service contract with a utility in eastern Canada were

also a factor. Physically, gas continued to flow from Canada

into the United States on Iroquois, but the marketer fulfilled

its Canadian contract by nominating a reverse flow and net

import volumes were reduced.

The pipelines and the LDCs serving New England had been

issuing flow restriction and operational flow order (OFO)

notices for several days before the price spike, indicating that

they had little operating flexibility. On January 7,

Tennessee, Texas Eastern, and Algonquin posted critical

notices, restricting interruptible services and “due shipper”

gas4 in market areas and requesting that shippers remain in

balance – actually flow what they claimed they would.

Further, Tennessee disallowed “supply to market” nomination increases, limiting supply receipts to the market area.

By the morning of January 14, Tennessee and Algonquin

posted critical notice OFOs with penalties for shippers deviating from nominations, in addition to the prior restrictions. Algonquin also issued a critical notice OFO requiring

shippers and delivery point operators to limit the daily discrepancy between scheduled and actual deliveries to 2 percent or less, with unauthorized quantities charged a

$15/dekatherm penalty. Tennessee Natural Gas Pipeline’s

balancing alert OFO for Zones 5 and 6 included a potential

penalty of $15/dekatherm, plus the applicable index price.

Iroquois, in anticipation of cold weather, requested on

January 13 that shippers take their exact scheduled quantity

(disallowing daily over-runs and hourly takes in excess of

120 percent of contracted capacity during this period). 

As conditions moderated from January 16 to 18, the

pipelines lifted the balancing OFOs but typically maintained

critical-notice restrictions. With improved operating conditions, Tennessee lifted its balancing alert OFO for Zones 5

and 6 effective January 16, 2004. On the same day, Iroquois

lifted hourly balancing and flow control conditions. On

January 17, the Portland Natural Gas Transmission System

lifted a critical notice requiring shippers to stay within 105

percent of their daily nominations and Algonquin lifted its

two-percent balancing OFO.

LDC Operations 

During this period, LDCs in New England experienced

“design” winter weather conditions of -15–degree

Fahrenheit wind-chill adjusted average temperatures—heating conditions they are designed to serve. Aggregate New

England LDC natural gas delivery, or “sendout” by source, is

shown in Figure 3. On January 15, total LDC load exceeded

“design” sendout by 112,000 MMBtu/day, or 3 percent of

design capacity.

On January 13, LDCs used all available flowing pipeline supplies and began to pull substantial volumes from local “peak

shaving” capacity—primarily liquefied natural gas (LNG).

The LDCs also bought spot market natural gas to supplement their other supplies. The spot purchases helped LDCs

State of the Markets Report • June 2005 15

Markets Under Stress: New England Reacts to Record Cold

Portland

Maritimes

Algonquin

Transco

Iroquois

Tennessee

Texas Eastern

Portland

Maritimes

Algonquin

Iroquois

Tennesse

Texas Eastern

Transco

Source: New England LDCs.

Fig 2: Pipelines Serving New England
16 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

maintain an orderly drawdown of limited peak-shaving supplies. One instance of loss of natural gas service occurred

January 16 in Hull, Massachusetts, when KeySpan lost pressure at the far end of a lateral in the Hull area, causing several hundred customers to lose service. Demand, in that case,

exceeded the capacity of the lateral—a situation later remedied by installation of a new distribution line. Service was

restored within 12 hours.

Peak-shaving supplies were critical to serving LDC load

when heating demand exceeded pipeline capacity. From

January 14 to 16, natural gas from peak shaving facilities

served 23 percent of total load. Figure 4 shows aggregate

New England peak-shaving capacity, usage, and LDC spot

purchases during that period. Peak shaving is designed to

operate for a brief period, usually one to three days. As a

rule, actual peak-shaving capacity varies, depending on factors such as prior use. 

Like the interstate pipelines, LDCs in New England issued

OFO balancing notices to protect their systems and to maintain consistency with the upstream pipelines. Beginning

January 8, Southern Connecticut Gas Co. and Connecticut

Natural Gas posted critical day OFOs for January 9, limiting

balancing allowances to 2 percent for under-deliveries and

10 percent for over-deliveries. On January 9, Yankee Gas

issued an OFO limiting under-deliveries to 2 percent and

over-deliveries to 20 percent. Penalties were significant at

three times the prevailing spot price. On January 14,

NSTAR and Keyspan Energy initiated “critical days” for

under-deliveries, with penalties of up to five times the daily

spot price. The same day, the New England Gas Co. and

Bay State Gas also issued OFOs for 2 percent imbalance

tolerances.

Analysis of natural gas spot market trading 

OMOI analyzed trading statistics obtained from ICE.5 The

data showed no excessive concentration or unusual trading

patterns. Table 1 shows market shares for the five largest

buyers and sellers in the Northeast physical natural gas markets from January 13 to 16. 

Markets Under Stress: New England Reacts to Record Cold

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1/12/04 1/13/04 1/14/04 1/15/04 1/16/04

MMBtu/day

Peak shaving used

Spot purchases

Peak shaving capacity

Peak shaving used

Spot gas buys

Source: New England LDCs.

Fig 4: Spot Gas and Peak Shaving

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

4,000,000

01/12/2004 01/13/2004 01/14/2004 01/15/2004 01/16/2004

MMBtu/day

$34.36 $20.50 $18.7

$9.73

$9.70

Pipeline

Transport

Storage

Peak

Shaving

Spot

Market

Design Capacity

Source: New England LDCs.

Fig 3: LDC Sendout Reached Design Capacity

Largest Sellers Largest Buyers

Trader Volume Percent Trader Volume Percent

(MMBtu) (MMBtu)

A 241,900 10.7 A 354,500 15.6

B 191,999 8.4 F 232,700 10.2

C 168,600 7.4 G 174,300 7.7

D 158,400 7.0 E 170,600 7.5

E 155,200 6.8 H 143,400 6.3

Source: Derived from ICE data January 13-16, 2004.

Table 1: Spot Transactions
Trader names are kept confidential, but the traders are

labeled by letter in descending order of sales and purchase

volumes.6 Based on the data in Table 1, the spot natural gas

market does not appear to have been dominated by a large

seller that might have been in a position to exercise market

power.

Analysis of individual trades shows that prices were driven

by buyers competing for a limited supply of spot market gas

during the period. On the ICE platform, prospective buyers

post bids to buy and prospective sellers post offers to sell.

When supply is unconstrained there is a degree of give-andtake in price formation. A seller may retreat from a high

offer to sell and lower its offer to entice a buyer to buy, or

accept the buyer’s bid as posted. Buyers can effectively do

the same. During December 2003 trading, as a comparison

when the gas market was unconstrained, the patterns of

bids and offers show that sellers would take buyers’ bids at

about the same rate as buyers would take sellers’ offers. A

greater number of bids and offers were left on the table. The

December pattern is shown in Figure 5. The left side of the

figure shows that from January 13 to 16 there was little giveand-take over prices. On January 13, no bids to buy were

accepted and only a few offers to sell were rejected. On

January 14, prices averaged $63.50/MMBtu when all offers

to sell were taken and all bids to buy were rejected. By

January 15, buyers were more successful when prices

declined to $18.60/MMBtu at the highest. On January 16,

the trading pattern reverted to one more like December. 

From January 13 to 16, natural gas prices appear to have

been driven by buyers with unfulfilled obligations competing for limited spot market supplies. 

Retail marketers, as a business strategy, often chose to rely

on the spot market rather than reserve capacity for unusual

conditions. Some LDCs charged penalties of up to five times

the prior day’s spot market price when load exceeded the

supply tendered by the marketer. On January 14, the short

supply penalty would have been $105/MMBtu (or five times

the prevailing index price of $21.00/MMBtu) for Bostonarea markets. A marketer in short supply would rather pay

the prevailing $63.50/MMBtu price than incur a

$105/MMBtu penalty. 

During extreme weather, LDCs rely on peak shaving to

serve loads over and above natural gas stored or flowing.

Peak-shaving sources typically have a limited inventory that,

once exhausted, generally is gone for the season. LDCs husband their peak shaving carefully, especially early in the

winter, to be prepared for contingencies that might arise

later in the season. For example, supplies are especially

short when late winter cold occurs after underground 

storage inventories have been depleted.7 Loss of service to

customers can be extremely expensive for an LDC. Such

events damage a company’s reputation and impose costs

required for relighting pilot lights house-by-house. Access to

spot gas is, consequently, extremely valuable. 

Power Market Operations

From January 14 to 16, ISO-NE struggled to keep the electric

grid operating in the face of record winter demand and

widespread generation outages. Although New England has

more than 32,700 MW of capacity, ISO-NE had difficulty

serving winter peak loads that averaged 22,400 MW during

the cold snap due to unexpectedly high outage levels for gasfired generation.

During the past six years, the natural gas portion of New

England’s generation capacity has increased dramatically,

State of the Markets Report • June 2005 17

Markets Under Stress: New England Reacts to Record Cold

50

40

30

20

10

0

10

20

30

40

1/13 1/14 1/15 1/16

 bids offers

offers not taken

offers taken

bids not taken

bids taken

Average for 

Dec. 8-31

50

40

30

20

10

0

10

20

30

40

12/31

Source: Derived from ICE data.

Fig 5: ICE Trading
18 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

from 12 percent in 1998 to 41 percent in 2004. As shown in

Figure 6, gas-fired generation outages were more frequent

than with other fuels, and outages jumped sharply when

spot prices spiked. Several factors contributed, including

tight gas supplies, pipeline operational conditions, equipment failures related to extreme cold weather and difficulties in aligning fuel acquisition with power market prices

and commitment timelines.

ISO-NE struggled to get enough generation on line

On January 13, ISO-NE’s day-ahead estimate indicated it

would have enough generation to meet expected electric

loads. ISO-NE had granted economic outages of 2,327 MW

and estimated that it would still have a surplus of 583 MW

for operations on January 14. After declaring economic-outage status, some generators then sold their firm natural gas

supply into the spot market, assuming that they would not

be called upon to run. Under ISO-NE rules, generators were

allowed to request an economic outage if they believed the

price of power would be lower than their marginal cost of

operation.

By January 14, ISO-NE increased its load forecast by 300

MW. Early that morning, an additional 822 MW of generation became unavailable, 507 MW of which was gas-fired.

ISO-NE was left with a projected reserve deficiency of 84

MW. ISO-NE was given little advance notice of the precarious supply situation for most of the natural gas units. At

10:00 a.m. on January 14, ISO-NE ordered all of the generators that had declared economic outages to return to service

as soon as possible. It also cancelled prescheduled maintenance and other work on critical transmission lines, generators, and communications links.8

Between 5:00 and 7:00 p.m. on January 14, ISO-NE implemented OP4 Actions Number 1 and Number 6 because the

Markets Under Stress: New England Reacts to Record Cold

0%

10%

20%

30%

40%

50%

60%

Jan 7 Jan 8 Jan 9 Jan 14 Jan 15 Jan 16

Percent outage

$0

$10

$20

$30

$40

$50

$60

$70

$/MMBtu

Gas Generation

Outages

Other Generation

Outages

Natural Gas Price

Source:Derived from Platts Gas Daily and ISO-NE data.

Fig 6: Increased generation Outages

Generation Available (MW) Type Outage

Ran Didn’t Run Total No Fuel Mechanical Total

Gas only 4,271 6,061 10,332 2,964 3,097 6,061

Gas/Oil 2,020 1,012 3,032 36 976 1,012

Oil/Gas 2,850 165 3,015 56 109 165

Oil+Jet+Diesel 3,994 843 4,837 0 843 843

Hydro 3,007 262 3,269 125 137 262

Coal 2,409 430 2,839 0 430 430

Nuclear 4,399 12 4,411 0 12 12

Wood+ 762 143 905 0 143 143

Total 23,712 8,928 32,640 3,181 5,747 8,928

Source: Derived from ISO-NE data. * Generation that sold fuel estimate at 1515 MW based on generator gas sales of 290,396 MMBtu/day, 8000 MBtu/MW-hr heat rate.

Table 2: ISO-New England Unit Status and Fuel Type on January 14, 2004 at 6:00 pm
large number of outages combined with higher-than-expected loads caused it to experience a 108 MW shortfall in 

operating reserves.9 By 6:00 p.m., at the time of the peak,

outages had increased to 8,928 MW (see Table 2). Imports

during this period totaled 350 MW, nearly half the available

interchange capability. Only one of the eleven units on 

economic outage actually made it back on line. The demand

saving from demand-response programs was about 200

MW. Despite the reserve deficiency, all load was served. 

The situation seemed to improve on January 15, but conditions deteriorated before they recovered late in the evening.

ISO-NE’s morning report listed outages of 7,972 MW and a

777 MW capacity surplus, a forecast that proved optimistic

for much of the day. Throughout the day generation availability was volatile—some units came back on line, while

others declared weather-related outages. During the afternoon, some dual-fired generating units in New York began

converting from gas to oil. Coordination between ISO-NE

and the New York Independent System Operator (NYISO)

resulted in an increase in New York-to-New England transfers from 800 MW to 1,400 MW. During the afternoon,

NYISO exported up to 1,100 MW to New England. At 6:00

p.m., actual outages exceeded the morning forecast, totaling

8,369 MW. In Southwest Connecticut, unexpected generator outages led to concerns about the area’s ability to cover

the loss of its second largest contingency. 

At 7:30 p.m., ISO-NE issued a press release, stating that it

was “taking precautionary measures, up to and including

preparing for rotating blackouts, to maintain the integrity of

the bulk power system”.10 The press release also requested

that consumers conserve energy. Helpfully, four units, representing another 938 MW that had initially declared economic outages, returned to service and contributed an estimated 278 MW. The net result was that ISO-NE finished

January 15 with a 717 MW surplus. 

On the morning of January 16, ISO-NE predicted a 701 MW

surplus and 22,727 MW of load. The morning forecast

turned out to be overly pessimistic. As actual load was nearly 10 percent less than forecast11 and six more units representing 1,661 MW that had declared economic outages

returned to service. At the time of that day’s peak, actual

outages totaled 6,328 MW compared to the 8,128 MW forecast that morning. The surplus at the time of the peak was

2,184 MW. 

Reasons for the outages

A total of 7,073 MW of the natural gas-fired New England

generation fleet of was out of service at the time of the peak

on January 14, 2004. Fully 3,000 MW was out of service due

to lack of fuel. The rest was out for mechanical reasons,

much of that weather-related. Many generators reported

problems, for example, with frozen fuel and water lines, air

and river water intakes clogged with ice and cold-damaged

pump seals.

Most of the gas-fired generation capacity in New England

was not supported by firm pipeline capacity, but relied

instead on interruptible transportation, secondary firm, offpeak supply from LDCs, and spot market natural gas. These

supplies were unavailable under high heating-demand conditions. Only 40 percent of natural gas-fired generation was

supported by firm transportation capacity.12

Lack of physical gas supply due to transportation or supplier

interruptions was responsible for approximately one-half of

the fuel-related gas outages. All of the units that declared

economic outages were Installed Capacity (ICAP)

resources.13 

Several units had dual-fuel capability but were unable to

run, with operators contending that air-quality permits

allowed them to use oil only when natural gas was physically unavailable. As a consequence, their dual-capability was

of no benefit when it was uneconomical to burn gas or when

gas was restricted to ratable volumes that were insufficient to

run the unit. Another generator stated that it was forced to

de-rate its unit because it had reached its daily NOx limits.

Finally, owners of several dual-fueled generators stated that,

though their units were listed as dual-fueled, their actual

ability to use an alternate fuel was (1) limited by the configuration of their units, (2) nonexistent because they ceased to

maintain costly reserves of fuel oil onsite or (3) the parts necessary to operate on oil had not been installed.

Generators with firm gas supplies saw few clear economic

incentives to operate. Under the ISO-NE tariff, generators

State of the Markets Report • June 2005 19

Markets Under Stress: New England Reacts to Record Cold
20 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

were entitled to elect not to run if it was uneconomical for

them to do so.14 This economic calculus allowed them to

consider opportunities lost by committing the generation

resource to ISO-NE. Differences between natural gas and

electric timelines for activities in advance of gas or power

flow would have exposed a generator to significant economic risks, particularly during periods of high price volatility in

the natural gas spot market. 

Timeline Risks

To assure the availability of natural gas when called upon to

run, a generator had to nominate pipeline capacity before it

was assured that its offer would be successful in the ISO-NE

market. Natural gas transportation nominations were

required by 12:30 p.m. to guarantee primary firm-point

reservation, well before the 4:00 p.m. day-ahead power market schedule was issued. If the offer were not accepted, the

generator would have natural gas it might have difficulty

selling or arranging for delivery to an alternate point. If natural gas were undelivered, the generator could have faced a

severe imbalance penalty or had difficulty getting the gas

returned until “shipper due gas” restrictions were lifted.

Figure 7 compares the conflicting timelines for the gas and

electric markets.

Likewise, if a generator offered its units to ISO-NE without

securing gas because it did not expect the unit to be accepted,

the company would be at financial risk of having to purchase

gas in the intraday market at a price significantly higher

than its offer, or purchase replacement power at unpredictable real-time LMP prices. If a generator believed it likely that its offer would not be accepted or that it would have

difficulty obtaining gas if it were accepted, opting out of the

power market became the economically rational decision.

Negative Spark Spreads

Prices for power in ISO-NE’s day-ahead market produced a

negative “spark spread” through the cold snap. A spark

spread is negative when fuel costs for generation exceed the

market value of power. During the cold snap, the real-time

market showed a negative spark spread for all but a handful

of hours. The failure of electric energy prices to move high

enough to make gas-fired generation economical was a root

cause of the reserve shortfall during this period. Figure 8

shows spark spreads from January 14 through 16.

On January 13, the day-ahead market produced a loadweighted average power price of $113/MWh for January 14

operations. The average natural gas price for the January 14

flow day was $21/MMBtu. An efficient, combined-cycle

generator with a 7,000 MMBtu/MWh heat rate would

require a power price of at least $147/MWh to cover fuel

Markets Under Stress: New England Reacts to Record Cold

Gas

Markets

Power

Markets

Gas Flow Day

Intra-day 2

pipeline

nomination

deadline

Intra-day 1

pipeline

nomination

deadline

Operating Day

Offers from DA and reoffer 

period are used to supply 

this market.

Evening

pipeline

nomination

deadline

Timely

pipeline

nomination

deadline

Typical

gas 

commodity

purchase 

deadline

09:00 to 

11:00

12:00

Day-ahead

bids and

offers due

by noon

4:00

DA LMPs

DA Schedule

Interface

Demand

Supply

ETs

4:00 to 6:00

Re-offer period

Must run 

adjustments 

Regulation offers

12:00 p.m.

12:00 a.m.

12:00 p.m. 01:00 p.m.

12:00 a.m.

01:00 a.m.

10:00 p.m.

01:00 p.m.

11:00 

06:00 

12:00 a.m.

01:00 a.m.

04:00 

05:00 

06:00 

07:00 

09:00 

10:00 

11:00 

12:00 p.m.

01:00 a.m.

01:00 p.m.

Calendar Day 1 Calendar Day 2 Calendar Day 3

Fig 7: Natural Gas and Electric Market Timeline
State of the Markets Report • June 2005 21

Markets Under Stress: New England Reacts to Record Cold

costs. With market prices clearing below what was needed

to attract natural gas-fired generation, some operators concluded there would be enough non-gas generation to serve

the expected load. In response, they requested economic

outages from ISO-NE on January 13 to sell their supply into

the natural gas spot market. In approving these requests,

ISO-NE believed (at that time) that there would be sufficient

non-gas power available to cover anticipated load. 

Factors Behind Negative Spark Spreads 

Power buyers submitted load-price bids in the day-ahead

market that cleared only a portion of the anticipated realtime load. Through their load-price bids, buyers signaled

that they were unwilling to pay the marginal cost of gasfired power, or that they were unaware that gas prices

would rise as high as they did. As a result, the day-ahead

market cleared at a price below the marginal cost of natural

gas-fired generation. This meant that a substantial portion

of real-time load would have to be served with power bought

in the real-time market. Figure 9 shows the gap that developed between day-ahead and real-time load from January 14

through 16. 

Much of the real-time load was served by reliability-dispatched units, reducing the level of load cleared in the realtime market. During the night of January 13-14, ISO-NE

experienced a greater-than-anticipated level of outages, 

leaving ISO-NE with insufficient reserves. ISO-NE responded by recalling natural gas units on economic outage status.

Generators that made it back on line were paid their offer

price, but that price did not affect the market clearing price.

Payments to reliability-committed units were recovered

through “uplift” charges that did not directly affect the 

energy market price. 

Day-ahead bids for January 15 also failed to clear at prices

high enough to attract gas-fired power generation. The spot

gas price at that time averaged $63/MMBtu, indicating that

a power price of at least $441/MWh would be needed to

make gas-fired generation economical (at a 7,000 heat rate).

The load-weighted average day-ahead power price, however, was only $316/MWh. Even though natural gas prices

were available then and it was clear that gas-fired generation

would be needed, the market still did not clear at a price high

enough to attract natural gas-fired generation.

Gas Sales by Electric Generators Helped LDCs Maintain

Service

Power prices in the ISO-NE day-ahead and real-time 

markets made it more economical for a generator to sell its

natural gas supply on the spot market than to produce power.

-$500

$0

$500

1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47

January 14 January 15

Spark Spread Value ($/MWh)

Real-time Spark Spread

D-A Spark Spread

Spark spreads calculated using Gas 

Daily indices for Algonquin citygate 

on Jan. 13-15, and an average heat 

rate of 8,120.

High spark 

spread of 

$750/MWh 

Source: Derived from Platts Gas Daily and ISO-NE data.

Fig 8: Day-ahead and Real-time Spark Spreads

Day Ahead Cleared 

Load

Real-time Actual Load

5,000

7,000

9,000

11,000

13,000

15,000

17,000

19,000

21,000

23,000

25,000

1/12/04 1/13/04 1/14/04 1/15/04 1/16/04 1/17/04 1/18/04 1/19/04 1/20/04 

Load (MWh)

Day Ahead Cleared Load

Real-time Actual Load

RT Peak 

1/14: HE18, 

RT Peak 1/15: HE19, 

22,732MW RT Peak 1/16: 

HE18, 21,885MW

All times are 12 am.

Source: Derived from ISO-NE data.

Fig 9: Day-ahead Loads Fall Short of Real-time Loads
22 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

The spot market served to reallocate natural gas supply from

electric generation to heating service in response to clear

price signals. Natural gas sales by generators helped increase

supply on the spot market, benefiting LDCs needing supplemental natural gas to protect their limited peak-shaving

inventory. Absent such sales, spot prices could well have

reached even higher levels. Figure 10 compares LDC spot

purchases to natural gas sales by electric generators. The

quantity of spot natural gas bought by LDCs was comperable

to the amount sold by electric generators. 

Conclusions

The natural gas spot market functioned competitively in

rationing supply. Although spot natural gas prices reached

extraordinary levels, a Commission investigation found no

indication that these prices were the result of market manipulation. The investigation also found no evidence that

pipeline capacity was withheld, no evidence that natural gas

supply was withheld, and no evidence of manipulative trading behavior. Prices appeared to be the result of a supply

shortage driven by extraordinary demand that left little

residual supply available for allocation through the pricedriven spot market. Buyers were willing to pay record prices

because the consequences of failure to obtain supply exceeded the cost of paying these unusually high prices. The high

spot prices provided the driver for the beneficial movement

of gas from the power sector to the heating market, without

which continuity of gas service and the public health and

safety could have been imperiled. 

The natural gas-electric interface timeline needs better

coordination, but infrastructure constraints will limit

benefits. Natural gas-fired generators must coordinate their

operations consistent with both natural gas and electric

business practice timelines. Under current timelines, generators must purchase and schedule pipeline transportation

before day-ahead power schedules are announced. The gas

operating day commences at 10:00 a.m., while the power

day commences at midnight. Thus, power operations straddle two natural gas days, and vice-versa. Under less stressed

operating conditions, the natural gas misalignment can be

managed using pipeline imbalance tolerances. When natural gas prices spike and display day-to-day volatility, the

operating-day overlap and schedule mismatch can expose a

generator to significant costs and potential losses. Making

the natural gas and electric day synonymous could reduce

the inter-day price mismatch exposure. It may be more difficult, however, to resolve the problem of synchronizing

natural gas commitments with power commitments,

because one part of the deal must be committed to before the

other can be entered into. 

Further hourly flexibility for pipeline transportation services could help match power and gas scheduling. Hourly flexibility on pipelines is more difficult to provide when a

pipeline is running close to capacity. When natural gas

capacity is constrained, pipelines have little flexibility to

handle the sudden withdrawals involved with real-time

power dispatch. 

In response to operational problems revealed by this 

incident, ISO-NE implemented a set of cold-weather procedures intended to make electric generation more secure

when natural gas supplies are tight. Two key provisions

would address the timeline problems that arose last winter.

First, ISO-NE will cancel scheduled economic outages and

request that dual-fuel generation switch to alternative fuels.

Second, ISO-NE will move the offer deadline ahead for 

day-ahead supply bids from midnight to 9:00 a.m. and

announce reliability run commitments by 10:00 a.m. This

change will allow those units chosen for reliability commitments to make gas supply arrangements within the gas 

market purchase and pipeline nomination period that 

closes at 12:30 p.m.

Markets Under Stress: New England Reacts to Record Cold

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

1/12/04 1/13/04 1/14/04 1/15/04 1/16/04

MMBtu/day

New England LDC Spot Buys

Generator gas sales

Source: Derived from ICE data.

Fig 10: Spot Natural Gas Transactions
The event revealed the consequences of barely sufficient

infrastructure. The extreme weather put the New England

gas and electric systems under significant, simultaneous

stress. The systems succeeded in serving full electric and

firm natural gas load under record demand, but operated

very close to physical limits. Natural gas system constraints

were the primary driver of high prices, which in turn made

the availability of natural gas-fired generation problematic.

Increasing demands have been placed on the natural gas

transmission system in recent years, both in New England

and in eastern Canada. Demand growth in these areas has

exceeded the rate of new pipeline capacity additions.

Additional pipeline or LNG import capacity would increase

supply and reduce the frequency or severity of winter pricespike episodes. Reduced dependence on pipeline transmission for winter peak service is another potential solution.

LDC peak shaving played a key role in maintaining service

during this period. Expansion of peak-shaving capacity

could prove to be more economical than new pipeline capacity. Reduced dependence on natural gas-fired generation

during winter peak periods could also reduce exposure to

pipeline constraints. Increased oil backup capacity and

more flexibility in the use of oil during gas-system stress

episodes could play an important role. Expanded electric

transmission links to other regions would also reduce the

vulnerability of the electric system to gas system constraints.

The ISO should assess relying more on market mechanisms and less on “out of market” reliability measures to

assure sufficient real-time supply. Negative spark spreads

for natural gas-fired power in the real-time market were

largely a result of ISO-NE’s practice of scheduling the highest cost units as reliability resources. The energy produced

by these units reduced the amount of power clearing the

real-time market and consequently avoided the higher-cost

portions of the power supply curve. By meeting a substantial percentage of the power requirement with reliability

units, the market did not clear at a price high enough to

attract natural gas through market signals. Rather than

meet a substantial portion of peak demand through reliability run instructions, ISO-NE should evaluate allowing the

real-time market to produce the needed power at the marginal cost of incremental production.

Further, depending on natural gas units for reliability

reserves under constrained pipeline operations may not provide the needed level of reliability. To be useful for reliability, a generator must be able to ramp up quickly to offset the

loss of other system generation or transmission capacity.

When the pipeline system is running at full capacity, it may

not be possible for a natural gas unit to pull the supplies

needed to ramp to full power output on a moment’s notice.

Thus, ISO-NE’s practice of counting stand-by natural gas

unit capacity as a reliability reserve may overstate realistically available reserves. From a reliability perspective, assigning generation units with on-site fuel, oil for example,

would provide a higher level of assurance that reserves

would run when called upon in a contingency situation.

State of the Markets Report • June 2005 23

Markets Under Stress: New England Reacts to Record Cold
24 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Markets Under Stress: New England Reacts to Record Cold

1 Energy Risk, March 2004, 74.

2 Some observers take a different view. In a July 6, 2004

press release, Connecticut Attorney General Richard

Blumenthal stated that “the cold snap revealed that current

market rules are not only inadequate to protect the public

safety and the region's power grid, but instead may work to

undermine the reliability of New England's electric grid."

http://www.cslib.org/attygenl/press/2004/util/coldsnap.htm

3 The Algonquin citygate price reflects spot sales at LDC

citygates in Connecticut, Rhode Island, and

Massachusetts.

4 A “due shipper” restriction prevents a shipper from recovering excess gas left on the pipeline during a prior period

to preserve line pack. 

5 ICE is, by no means, the only trading platform for spot

natural gas on a daily basis. There is no one source for spot

pricing information (see the “Energy Market

Information” essay for more details). However, ICE does

maintain detailed, time-stamped transactions in its system and, consequently, is helpful in understanding trends

in trading at the time. ICE prices were cross-referenced

with published indices for the dates referenced and found

to be similar.

6 Note that two trading entities show up on both the list of

top five sellers and buyers. In effect, these traders were

speculating that day in physical next-day gas deliveries,

something akin to “day-trading.” Given the low concentrations of all participants, this activity does not concern

OMOI.

7 Refer to our February 2003 spike study.

8 ISO New England, Interim Report on Electricity Supply

Conditions in New England during the January 14-16, 2004

“Cold Snap.”

9 Action 1 is the notification of generators by ISO-NE that a

capacity shortage exists, and Action 6 allows the depleting

of 30-minute reserves to begin. 

10 See ISO-NE January 15, 2004 Media Advisory entitled

“ISO New England Requests Voluntary Electricity

Conservation—Appeal Extended Through Friday Night,

January 16, 2004” http://www.iso-ne.com/iso_news/

2004_Archive/Conservation_Request_Extended_01_15

_04.doc’

11 Schools were closed because of the cold and the ISO continued to advise customers to conserve energy.

12 FERC, New England Natural Gas Infrastructure staff report,

Docket No. PL04-1, December 2003.

13 The concept of ICAP was instituted by the power pools as

a first-line reliability measure to cover electric load in the

pool. To insure that there are adequate generation

resources to serve load, the ISO calculates the summer and

winter capacity requirements. After adjusting this figure

to reflect outages, the ISO allocates the requirements to

the participants based on their customers’ contributions

to the previous year’s coincident peak. Participants can

meet their ICAP obligations either with generation they

own or control. They can also procure ICAP in monthly

auctions conducted by the ISO or in the secondary market. ICAP resources are required to submit offers into the

day-ahead market for all capacity that is not self scheduled. They are also required to adhere to certain reporting, audit, and outage scheduling requirements.

14 See ISO-NE Market Rule 1.

Endnotes
I

n 2004, generation remained the focus of wholesale electric infrastructure

investment, just as it has been since the 1990s. The level of investment in

generation continued to far outstrip transmission on both an absolute and 

relative basis. This was so even though investment actually increased in

transmission and declined in generation from 2003 to 2004.

Despite the continued dominance of generation, a

renewed recognition of transmission’s contribution to

electric reliability and efficiency led to the announcement

of ambitious transmission investment plans by both 

regulated and unregulated players. The relative paucity of

projects completed in 2004 did not reflect this shift in

interest, but rather the legacy of less interest in prior years,

long investment lead times, and other impedements to

transmission investment and construction.

New 2004 generation construction generally reflected

investment decisions made in the past as well.

Consequently, fuel and sponsor trends remained: gasfired generation dominated additions across the country

and independent power producers (IPPs) sponsored the

largest portion of new capacity.

ELECTRIC MARKET

INVESTMENT AND MERGER TRENDS

State of the Markets Report • June 2005 25
About 931 miles of new transmission lines of 230 kV or

greater were built in 2004, an addition of roughly 0.6 percent

of installed capacity (by mile).1 In contrast, more than 20

gigawatts (GW) of new generation capacity entered operation, adding 2.3 percent to the electric generating fleet.2 The

low level of transmission investment continued a trend that

has existed at least since the beginning of the 1990s.

According to a study by Trimaran Capital Partners of FERC

Form No. 1 data for the years 1992–2003, the annual growth

in net investment in transmission plant by investor-owned

utilities has averaged 2 percent.3 This growth contrasts with

higher levels of load growth, generation, and distribution

investment in the period.4 Trimaran’s study showed that

transmission’s 30 percent of total transmission and distribution plant in service in 1992 declined to 26 percent of plant

in service by 2003.5

Transmission additions varied significantly by reliability

region, with no miles added in the independent system

operators of New England (ISO-NE), New York (NYISO),

or the Midwest (MISO). Additions included 309 miles (1.3

percent) in the Pacific Northwest, 131 miles (1.7 percent) in

the Southwest Power Pool (SPP), and 149 miles (0.4 percent)

to the installed base in the Southeast (see Figure 1).

Transmission circuit miles are not a complete representation of all the investment in the transmission system.

Substations, conductors, and other devices can also increase

transmission capacity and plant in service. 

Transmission plant addition figures from FERC Form 1 data

indicate a continued increase in transmission investment.

Those data show a continuation of steady investment

increases of 13.1 percent on a compound annual basis from

2000 through 20046 (see Figure 2). FERC Form 1 data for

2004 reflect preliminary filings. 

26 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Market fundamentals in 2004 did not generally signal a need

for new construction of generation, particularly of gas-fired

capacity. New generation announcements focused on coalfired and renewable projects. Regulated utilities, their 

affiliates, and public power participants based a greater 

proportion of their investment decisions not solely on 

current plant economics but also considered hedges for 

projected load growth.

Asset acquisitions increased. Many companies strove to stabilize financial profiles through asset sales. Strategic players,

such as investor-owned utilities (IOUs) and their affiliates

(i.e. affiliated power producers (APPs)) stepped up 

purchases of generation. Some lenders took equity ownership of facilities as sponsors defaulted on debt obligations.

Additional financial players with cash on hand (mostly

hedge funds and private equity firms, particularly those that

gained experience in the electric markets through secondary

debt investments) became more active in asset acquisitions

to meet investment targets. 

In addition, corporate managers began to reassess company

mergers as a strategic option for earnings growth. Private

equity funds were frustrated in their attempts to purchase

regulated utilities, but utility managers began to advance

corporate merger initiatives after a period of retrenchment

and balance sheet repair.

Electric Market Investment and Merger Trends

Transmission Investment

Source: Derived from NERC, ERCOT, Platts, and EIA data. See source note 1.

Fig 1: Transmission vs. Generation Additions

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%

California

ERCOT

ISO NE

Midwest

Northwest

NYISO

PJM

Southeast

Southwest

SPP

US

% Increase in Regional Capacity

2004 Generation Added (MW)

2004 Transmission Added (Miles)
Edison Electric Institute (EEI) data, based on a survey of historical and planned capital expenditures by EEI members,

also indicate an increase in annual transmission investment.

Specifically, EEI data show that transmission investment by

shareholder-owned utilities averaged twelve percent annual

growth from 1999 to 2003.7 In addition, the survey forecasts

an unprecedented increase in transmission investment over

the next few years. Plans do not always equal completed

projects. The EEI survey results for projected expenditures

in 2004 did not match preliminary FERC Form 1 data for

actual expenditures, which totaled $4.3 billion. The EEI 

survey’s forecasted expenditures were $4.5 billion, an indication that actual expenditures can fall short of estimated

budgets even in the near term. 

In 2004, equity and debt markets rewarded stable, regulated

operations (and the cash flows they generate) with premium

valuations. Within this context, transmission investment

gained new appeal to investor-owned utilities, which

responded with increased plans to build. Successful execution of planned investment goals in the transmission sector

can be difficult for several reasons:

• Developers face challenges in obtaining rights of way, siting, and licensing of electric transmission lines (challenges

typically even greater than the ones they face in the permitting process for gas pipelines and electric power

plants). 

• Regulatory uncertainty poses dilemmas. The uncertainty

can be as specific as that related to rate treatment for a

planned, delayed, or ultimately frustrated line. Or it can

be as pervasive and general as the difficulty in distinguishing reliability from efficiency projects. The resolution of

state and federal jurisdictional issues can, moreover, exacerbate cost recovery and cost allocation. 

• Revenue uncertainty can reduce incentives in both regulated and merchant contexts. For merchant or contract

generators, projecting and capturing future revenue can be

difficult. 

Anecdotal evidence pointed to difficulties in both areas with

and without formal regional planning organizations.

Northeast Utilities’ Connecticut Light and Power, for example, continues to attempt to build new high-voltage lines

into southwest Connecticut within the context of a regional

transmission organization (RTO). The construction of the

new lines has been delayed by local and state opposition and

by debate over how to allocate the costs involved within

New England. Attempts to enhance the links among southern California, the Pacific Northwest, and the Southwest are

impeded by the absence of a formal regional planning

organization. Growing recognition of the need to enhance

the grid in the wake of the August 2003 Northeast blackout

as well as the resulting attention to reliability, have spurred

many investor-owned utilities to announce more ambitious

transmission investment plans and to push forward on state

and regional projects. RTOs and regional planning organizations also pursue their own programs.

In addition to the plans announced by Northeast Utilities,

several other significant projects were in the offing in 2004.

• NStar announced plans to spend $200 million to construct a new 345kV transmission line from Stoughton,

Mass., a southern suburb of Boston, to south Boston to

ensure continued reliability of service and improve power

import capacity in northeast Massachusetts (NEMA).

The line is projected to be placed in service in summer

2006. 

• The Southern Company invested $1.3 billion in transmission lines and substations from 2001 through 2003,

expanding the Atlanta Loop and making other improvements to its system. In 2004, Southern constructed

State of the Markets Report • June 2005 27

Electric Market Investment and Merger Trends

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

2000 2001 2002 2003 2004 2005 2006 2007 2008

Millions of Dollars

FERC Form 1 Data

EEI Survey Projections

Source: Derived from FERC Form 1 and EEI data.

Fig 2: 2000-2004 Transmission Plant Additions
28 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

approximately 170 miles of new transmission lines and

upgraded an additional 764 miles of line. It also projects

an expenditure of nearly $3.1 billion on transmission and

distribution from 2005–2007, with slightly less than half

the amount to be spent on transmission. 

• Southern California Edison announced plans to spend

$1.6 billion through 2009 on transmission (as opposed to

a current transmission rate base of $1.1 billion) with $680

million to be spent on building a 230-mile, 500 kV line to

Arizona.

At the end of 2003, stand-alone transmission companies in

the Midwest owned 3 percent of the transmission assets that

investor-owned utilities owned nationally. These companies

continued to pursue investment levels that far exceeded

what they had pursued when they were part of integrated

utilities and far exceeded the 3 percent investment planned

by investor-owned utilities.

• American Transmission Company of Wisconsin invested

more than $500 million in its system from the time of its

formation in 2001 through 2004; the company planned to

spend an additional $315 million in 2005, as compared

with an initial transmission book value of slightly more

than $500 million. 

• International Transmission Company (formerly Detroit

Edison’s transmission system) spent $81 million in 2004

and planned to spend an additional $100 million in 2005,

compared with a net book value of approximately $775

million on transfer in 2002. 

• Michigan Electric Transmission Company (which was

formed through the acquisition of Consumer’s Energy

transmission system) spent and planned to spend roughly

$250 million by the end of 2009 as compared with a net

book value of $230 million on transfer of the company in

2002.

Electric Market Investment and Merger Trends

Investment in Electric Generating Assets

In 2004, almost 25 GW of generating capacity was added

across the country, down 50 percent from 2003 (see Figure 3.)

More generation was built by independent power producers

(IPPs) than any other market segment. IPPs sponsored 7.7

GW of the generation that reached commercial operation in

2004 (see Figure 4).

APPs and IOUs were more active in their construction 

programs than they had been in the recent boom period.

APPs built just over 6 GW, or 27 percent of total new generation. Investor-owned utilities built 18 percent of the new

capacity in 2004. Municipals and cooperatives placed into

service 11percent of the new capacity. Lenders completed 2

GW of generation projects that were turned over by troubled sponsors, adding 9 percent of the new generation.

As shown in Figure 5, gas-fired generation dominated additions. Almost 550 MW of coal-fired generators came on line

in PJM. Approximately 250 MW of renewable capacity was

added, primarily in the Midwest. 

Most additions were built in the Southeast, PJM, and the

Southwest, markets already experiencing regional overbuild

conditions. When measured as a percentage added to

Source: Derived from EIA's Electric Power Monthly Table ES3 and Platts POWERdat

data, as of 3/01/2005. IPP consists of IPP, COGEN, and Industrial.

-

10,000

20,000

30,000

40,000

50,000

60,000

70,000

2002 2003 2004

Summer Capacity (MW)

Fig 3: 2002-2004 Generation Capacity Additions
installed summer capacity by the new construction, PJM

added almost 10 percent and the Southwest added 5.4 

percent. 

These new additions increased excess capacity, adding

downward pressure on both energy and capacity prices in

the market, and reducing net revenues for gas-fired capacity

in most regions during the assessment period. 

New generator operations lag original investment decisions

by about two years for gas-fired capacity and by up to ten

years for coal-fired capacity. Hence, investment decisions

made during the period of high energy prices before 2003

drove asset additions in 2004. In many areas of the country,

generation additions increased reserve margins and reduced

net revenues, suggesting that investment decisions were

made using more optimistic projections of market conditions than were realized. 

Reserve margins and load data suggest that there were, in

most cases, adequate or excess resources and reserves to meet

regional demand during the assessment period. NERC 2004

summer reserve margins, which ran from a low of 12 percent in New York to a high of 77 percent in the Southeastern

Electric Reliability Council (SERC), are shown on Figure 6.8

They are compared with net revenues, calculated by FERC

for state of the art gas-fired combined cycle turbine (CC)

units (see Electric Almanac Overview and Regional Profiles

for regional details). As illustrated, there was a general trend

of inverse relations between reserve margins and net revenues—what we might expect as a general pattern. 

In addition to high regional reserve margins, gas price

increases resulted in reduced dispatch and compressed spark

spreads for variable operations of gas-fired capacity. 

Generation announcements reflected a shift in focus; new

generation investment decisions tended to address fuel

diversity and environmental concerns, with coal-fired 

generation and renewable energy resources. 

In 2004, natural gas prices reached three times that of coal,

with gas generally driving electric market prices. Coal-fired 

facilities generally experienced higher capacity factors and

attractive profits. With the existing coal fleet approaching

operating maximums and growing concern over fuel

diversity, environment policy effects, and associated price

risks, companies began to review the economic feasibility

of building advanced technology coal-fired facilities.

Though estimates vary, recent studies suggest that as much

as 80 GW of new coal-fired capacity has been announced 

in what appears to be a rush to secure permits and 

start the seven–to–ten year development process. More 

State of the Markets Report • June 2005 29

Electric Market Investment and Merger Trends

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

IPP Lenders MUNI APP IOU

Summer Capacity (MW)

Source: Derived from EIA's Electric Power Monthly Table ES3 and Platts POWERdat

data, as of 3/01/2005. Note: IPP consists of IPP, COGEN, and Industrial.

Fig 4: Capacity Additions by Sponsor Type

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

California

ERCOT

ISONE

Midwest

Northwest

NYISO

PJM

Southeast

Southwest

SPP

Summer Capacity (MW)

Nuclear

Oil

Renewable

Coal

Gas

Source: Derived from EIA and Platts data. See Source note 3.

Fig 5: 2004 Regional Capacity Additions by Fuel
30 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

conservatively, Cambridge Energy Research Associates

(CERA) estimated in its winter 2004–2005 North American

Electric Power Watch that 28.4 GW of coal-fired generation

was under active development or under construction. 9

In addition, “green” energy options, in particular wind projects, were spurred in late 2004 as the production tax credit

(PTC) was renewed and an increasing number of states

passed renewable portfolio standards (see Wind section). By

November 2004, a month after PTC renewal, over 1,400

MW of wind power projects had been announced or put

back on track, with 1,000–2,000 MW announced as

advanced stage, likely, or in development.10 GE Wind

Energy had already received contracts for 750 MW of turbines for 2004-05, and another 750 MW of 

commitments, valued together at $1.3 billion in new wind

development. 11

Electric Market Investment and Merger Trends

0

10

20

30

40

50

60

70

80

0%

10%20%30%40%50%60%

Net Revenues from Energy and Capacity ($/kW-yr)

SERC: 

STHRN

New

York

California

ECAR

New England

ERCOT

PJM

NWPP

SPP

AZNMSNV

Source: Derived from NERC and other data. See source note 4.

Fig 6: Reserve Margins vs. Net Revenues

Merger and Acquisition Activity

Asset Acquisitions

Most electric acquisitions in 2004 took place at the asset

level. Continuing the 2003 trend, many companies strove to

stabilize financial profiles through asset sales. The majority

of the facilities that changed ownership were sold by utilities

and their unregulated affiliates, seeking to exit noncore business lines, particularly those with merchant exposure. Both

generation with creditworthy power purchase agreements

and with merchant exposure were sold. A portion of the

troubled merchant plants that were unable to meet their

debt service saw completed formal transfer of equity to

lenders. Although a number of the sales were of single

assets, two large portfolios were also purchased by new owners: the Texas Genco and American Electric Power (AEP)

Texas Central portfolios.12 In aggregate, almost 36 GW of

generation, or nearly 6 percent of installed capacity, changed

hands in 2004, more than four times the 8 GW acquired in

2003. 

Generation changed ownership in all regions of the country

in 2004. Nearly 90 percent of the transfers, however,

occurred in four regions: Electric Reliability Council of

Texas (ERCOT) (with 39 percent of transfers), SERC (21 percent), Western Electricity Coordinating Council (WECC)

(15 percent), and New York/New England (12 percent).

These regions had high proportions of merchant assets. In

SERC, many assets stranded by the lack of regulatory

restructuring (and consequently available markets) were

selling at discounted prices. In contrast, the assets in the

remaining regions were poised to supply ISO/RTO markets,

alternative retail suppliers, or utilities that had divested

assets and now needed contracted supplies for load. They

could be sold to improve debt repayment abilities. 

IOUs bought 1.7 GW of generation in 2004, more than double the 0.7 GW purchased in 2003 (see figure 7). With the

backdrop of certain state regulatory and credit rating agency

policies, which effectively discourage power purchase agreements (PPAs), utilities in many cases decided against signing

PPAs with merchant generators. Instead they purchased

facilities from affiliates and non-affiliates alike to secure

retail supply for their service territories. In some cases these

transfers were proposed despite intervenor claims that some
assets were actually transferred at above market values or

that contract options were more economic. An example of

generation purchased by a utility from affiliates was Georgia

Powers’ acquisition of McIntosh from Southern Power.13 A

purchase from a troubled merchant company was NRG’s

sale of McClain to OG&E. 14 Municipals also actively participated in asset purchase from troubled sponsors to secure

supply for their internal load. 

APPs purchased 1.9 GW in 2004, almost a four fold increase

from the 0.5 GW purchased in 2003. PSEG Global acquired

the remaining 50 percent interest in their joint venture with

Panda. Constellation expanded its nuclear portfolio.

Sempra purchased a contracted Texas asset as well as half of

the portfolio divested by AEP in Texas, including the Coleto

Creek coal-fired plant.

In addition, 6.0 GW of capacity were returned to lenders in

2004 as sponsors walked away from projects that defaulted

on their debt obligations. Many of the facilities that lenders

took equity ownership of in 2004 faced operational or financial problems in earlier years. The official transfer process

took some time. The transfers required restructuring to

address operations and management of the assets. Lenders,

with limited ability or desire to run daily operations, hired

asset managers, energy managers, and O&M service firms in

an attempt to minimize current cash losses and maximize

valuations of these assets for future sale. 

An active secondary market for project loans developed in

2004, with original lenders selling debt to other banks and

hedge funds.15 In some cases, debt that banks had traded at a

deep discount was resold to hedge funds and other investors

at or near par value based on perceived interest in plant 

equity by buyers, or the ability to seek regulatory solutions

to distressed projects.16

Equity investors, including private equity investors, income

securities, and hedge funds were by far the largest purchasers, acquiring more than 23 GW, a significant increase

from the 0.8 MW purchased in 2003. In keeping with their

own organizational diversity, financial purchasers had different investment strategies. Much of the contracted generation was purchased for its bond-like yield characteristics.

The balance was purchased with the expectation that value

would be realized through contract restructuring and monetization. Some financial players bought merchant generation with the hope that they would be able to quickly sell or

contract it to load-serving entities with prospective need for

additional supply. Assuming that demand growth would

eventually eliminate reserve margin overhangs, others

bought merchant position at deep discounts with plans to

hold plants until values reverted to replacement cost. In the

interim these financial players, much like original lenders,

outsourced energy and asset management to an emerging

group of service providers as well as provided interim capital

for working capital carrying costs such as insurance, maintenance, and property taxes. 

Corporate Mergers & Acquisitions

At the corporate level, utilities and financial institutions

exhibited growing interest in mergers and acquisitions,

prompting many analysts to herald 2004 as the inauguration

of a new round of consolidation in the power sector. 

One utility-to-utility acquisition was closed and three were

announced, with the largest proposed in December:

• Announced in December 2003, Ameren closed its acquisition of Illinois Power Co. in September 2004.

• In January 2004, Black Hills Corp announced the acquisition of Cheyenne Light, Fuel & Power from Xcel Energy. 

State of the Markets Report • June 2005 31

Electric Market Investment and Merger Trends

0

5,000

10,000

15,000

20,000

25,000

Utility

APP

MUNI & COOP

Lender

Equity Investors

Investment Bank

IPP

Capacity (MW)

2003

2004

2005 & Pending

Source: Derived from EIA data. See source note 5.

Fig 7: 2003-2005 Generating Plant Sales and Transfers
32 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

• In July 2004, PNM Resources, the parent of Public Service

Company of New Mexico, announced the intention to

acquire TNP Enterprises, the parent of Texas New Mexico

Power Company from a group of private equity investors.

• In December 2004, Exelon announced its intent to merge

with PSEG, a plan that would create the nation’s largest

utility company by generation ownership, market capitalization, revenues, and net income.

However, two high-profile private equity attempts to

acquire franchise-regulated electric utility operations, both

announced in November 2003, failed in response to stiff

local resistance in 2004: 

• Kohlberg, Kravis & Roberts’ attempt to acquire

Unisource, the parent company of Tucson Electric Power,

through Saguaro Utility Group was unsuccessful. The

Arizona Corporation Commission rejected the aquisition

offer in December 2004.

• Texas Pacific Group’s attempt to purchase Portland

General from Enron’s bankruptcy estate (through acquisition vehicle Oregon Electric), met with local opposition

and a municipal counteroffer.

Electric Market Investment and Merger Trends
1 Transmission data based on OMOI analysis of NERC's Electricity

Supply & Demand Data Base as of April 19, 2005. ERCOT transmission data were retrieved from "Existing and Potential Electric

System Constraints And Needs Within The ERCOT Region" report,

October 1, 2004.

2 Generation data based on OMOI analysis of EIA's Electric Power

Monthly data and Platts. 

3 Transcript of Technical Conference on Transmission

Independence and Investment, Docket No. AD05-5-000 (April 22,

2005), Tr. 31. (Jon Larson, Trimaran Capital Partners).

4 Transcript of Technical Conference. Tr. 16-17 (Brendan Kirby, Oak

Ridge National Laboratories)

5 Transcript of Technical Conference. Tr. 32. (Jon Larson, Trimaran

Capital Partners.

6 FERC Form 1 data include accounts 352, 353–359.1. *FERC Form

1 data for 2004 is a preliminary data set based on 198 of 221

companies. The missing 23 companies accounted for 6.7 percent

of the Year Balance dollars in 2003. It was assumed that their

share of the total would remain constant in 2004. Transmission

addition levels for the 198 respondents, representing 93.3 percent of the whole ($3.99 billion) multiplied by (100/93.3) provides a preliminary 2004 transmission addition level of $ 4.28 billion. 

7 EEI Survey of Transmission Investment – Historical and Planned

Capital Expenditures (1999–2008) at 5 (Edison Electric Institute,

May 2005) (EEI Survey). The EEI Survey data are composed of

responses from 60 IOUs for 2003 expenditures and for forecasted budgeting. The survey included a breakdown of transmission

line construction costs and transmission substation costs, and

accounted for all Transmission Plant in Service reported on FERC

Form 1. 

8 NERC 2004 Summer Assessment/forecast for August with

Uncommitted Resources; net revenues reflect estimated profits

from energy and capacity markets as detailed in Electric Almanac

Overview and Regional Profiles in Appendix.

9 US Power Sector: Shifting Capital Spending Patterns, CERA Client

Services, January 17, 2005, 5.

10 See Assessing the State of Wind Energy in Wholesale Electricity

Markets, Docket No. AD04-13-000, November 2004.

http://www.westgov.org/wieb/meetings/windfall2004/briefing/FERCpaper.pdf

11 GE News Release October 18, 2004-

http://home.businesswire.com/portal/site/ge/index.jsp?ndmVie

wId=news_view&newsId=20041018005721&newsLang=en&nd

mConfigId=1001109&vnsId=681

12 In July, AEP closed on the sale of most of its Texas Central

Portfolio (10 power plants with a generating capacity of approximately 4 GW) to a joint venture of Sempra Energy Partners and

Carlyle/Riverstone Global Energy and Power Fund. In December,

most of the TX Genco assets (11 power plants with a generating

capacity of over 13 GW) were sold by CenterPoint to GC Power

Acquisition LLC, an entity owned in equal parts by affiliates of

The Blackstone Group, Hellman & Friedman LLC, Kohlberg Kravis

Roberts & Co. L.P., and Texas Pacific Group. 

13 Initially, Southern Power, an unregulated affiliate of Southern

Company, applied for FERC approval of power purchase agreements (PPAs) with regulated affiliates Georgia Power and

Savannah Electric for output from McIntosh. In hearings before

the Commission, interveners opposed approval of the PPAs on

the basis that they did not meet market-based rate standards for

affiliates. The Georgia PSC later directed Georgia Power and

Savannah Electric to acquire the facility to secure local supply.

Following asset acquisition, ongoing FERC proceedings were terminated. See Southern Power Company, 108 FERC 61,134

(2004); Southern Power Company, 104 FERC 61, 041 (2003).

14 In 2003, OGE applied for FERC approval of the purchase of 77

percent interest in the McClain facility owned by NRG Energy.

The Commission set it for hearing in which interveners opposed

approval on the basis that OGE's initial mitigation proposal was

insufficient to thwart potential for market power. Ultimately, the

acquisition and revised mitigation plan were approved by FERC in

2004. See Oklahoma Gas and Electric Company and NRG

McClain LLC, 108 FERC 61,004 (2004); reh’g denied, 111 FERC

61,075 (2005).

15 An asset that is trading “at par” is selling for its face value.

When the asset sells at face value, the bank has recovered the

amount of principal owed at maturity of the original loan. 

16 Merchant Power: Short Circuit Could Lead to Mega Returns,

Imperial Capital, LLC., January 31, 2005.

State of the Markets Report • June 2005 33

Electric Market Investment and Merger Trends

Endnotes
34 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

1. Transmission data based on FERC/OMOI analysis of NERC ES&D

Data Base, 2004 Updates from NERC as of April 19, 2005, ERCOT

data, and FERC Research. Generation data based on OMOI 

analysis of EIA's Electric Power Monthly data and Platts

PowerDat. Mileage is the number of circuit miles greater than

230 kV added to a transmission system. 

2. Based on EEI's planned total industry expenditures estimated

from 95 percent response rate to EEI's Electric Transmission

Capital Budget & Forecast Survey as of May 20, 2005.

FERC/OMOI applied a 2.45 percent annual inflation rate to EEI

results in real dollars; 2.45 percent was chosen based on the

Handy Whitman Index of Public Utility Construction Costs

2002–2003. 2004 FERC Form 1 reflects preliminary data. 

Note: EEI Data represent shareholder-owned electric utilities.

3. Analysis of EIA's Electric Power Monthly Table ES3 and Platts

PowerDat data as of March 1, 2005. Note: Energy sources are

merged in the following way. Renewable consists of black liquor,

landfill gas, wood, water, and wind. Oil consists of distillate fuel

and residual fuel. NG consists of natural gas. Coal consists of

waste coal. Data do not account for retirements.

4. Analysis of reserve margins from NERC 2004 Summer

Assessment/forecast for August with Uncommitted Resources;

net revenues reflect estimated profits from energy and capacity

markets as detailed in Electric Almanac Overview and Regional

Profiles in Appendix. 

5. Data were gathered from the EIA Electric Power Monthly - Table

ES4: Plants Sold and Transferred in 2003 and 2004, and Platt’s

PowerDat, as of March 15, 2005. Note: The following buyer

types were merged into one category: IPP consists of IPP, IPPCogen, and a retail supplier. Private equity consists of private

equity, financial arm of an industrial company, hedge fund, 

and royalty income trust. Utility consists of utility and holding

company.

Disclaimer: This report contains analyses, presentations, and conclusions that may be based on or derived from the data sources cited, but

do not necessarily reflect the positions or recommendations of the data

providers. 

Electric Market Investment and Merger Trends

Source notes
ENERGY MARKET

INFORMATION

State of the Markets Report • June 2005 35

In 2004, the Commission acted to improve energy market

information by:

• Working with the industry to improve the quality and

credibility of price indices for natural gas and electric

power;

• Focusing attention on gas storage data by settling

cases with two companies that inappropriately shared

storage information and with a third company that

may also have done so, by holding a technical 

conference on reporting, and by investigating an

anomalous inventory report that significantly moved

the market in November 2004; and

• Improving the quality of the Electric Quarterly

Report (EQR), in which jurisdictional companies

provide a comprehensive report of their physical 

electric sales.

Market efficiency depends on timely, reliable, and pertinent

information. In the aftermath of recent crises, the

Commission and market participants have become increasingly 

sensitive to these characteristics of effective markets. 

State of the Markets Report • June 2005 35
36 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Introduction

Information is the lifeblood of healthy commodity markets,

including energy markets. Market efficiency depends on the

quality and transparency of information. Without pertinent

and reliable information, individual participants will make

uninformed decisions, and efficiency will decline. 

If market participants find information difficult to obtain,

transaction costs grow and efficiency drops. Information

may also be costly to obtain or to use. Every market participant decides (tacitly, if not explicitly) how much to expend,

in effort and money, for market information. Well-functioning energy markets must meet the information needs of

a variety of different market participants, including traders,

price takers, and regulators. 

Traders. The category includes market makers with large

trading desks, speculators, and many others. These players

need access to pricing that they can trust for many different

energy products. Prices can vary by, for example, duration

(hourly, day-ahead, monthly, longer term), timing (now or

later), location (which implies valuing transmission), and

optionality. Traders can obtain such information from

transparent information sources, such as exchanges and

regional transmission organizations (RTOs), or because of

their active participation in the market itself, from less transparent sources like voice brokers and direct negotiation. 

Traders also use a wide variety of other information about

factors that may significantly affect price (such as weather,

outages, and load growth). They compete to obtain the best

information about the most important factors, and some set

up their own intelligence operations to do so. Market

demands drive traders to develop the most pertinent and

cost-effective information systems. As a result, the interplay

of many active traders can, in theory and probably in practice, create reasonably efficient pricing. 

Price Takers. This category includes companies that cannot

or will not invest their time or money to obtain detailed

market information, generally because they are too small or

because their core business interests lie elsewhere. Examples

include smaller independent producers and distributors,

public power and gas organizations, and many customers,

large and small. Price takers depend on reliable, commoditized pricing that does not require much research or

expense. In practice, they rely on transparent information

available from RTOs, exchanges, and published price

indices. They also depend on standardized forward instruments like futures contracts for risk management, though

they may actually buy such products through a broker or

marketer. In a competitive market, they depend on active

traders to generate efficient prices and, crucially, on some

reliable mechanism to report those prices to them.

Transparency and standardization are the key ways to make

information usable for price takers.

Regulators. Relevant regulators include FERC, the

Commodity Futures Trading Commission (CFTC), and

state public utility commissions. They need enough information to identify serious market abuses and flaws in the

way energy markets work. In recently deregulated markets

like some electric power, the ability to detect—and then to

correct—market flaws is particularly important.

Accordingly, it is vital that regulators have enough information to monitor market activity.

What information is available to regulators (and when)

depends largely on the structure of the market. Locational

marginal, day-ahead, and real-time pricing, along with

capacity and ancillary services within RTO markets, are

almost entirely transparent and make much information

available in real time. Such transparency rests on standardized operations and large, centralized mechanisms to collect

and disseminate the information. By contrast, most natural

gas markets and bilateral electric markets provide far less

detailed information, depending instead on trade publications to provide price indices. These markets are less transparent than RTOs but often serve a variety of industry needs

well. In time, such markets may develop more standardized

platforms, rather like the IntercontinentalExchange (ICE)

and Nymex, to provide comprehensive and reliable information akin to what is now available from RTO markets.

Finally, some electric power markets are almost entirely

opaque both to regulators and to price takers. In these markets (such as electricity in much of the Southeast), so little

information is available that price indices either do not

develop or have little value in price discovery.

In practice, the Commission has attempted to identify and

make use of all information available to it. For electric

Energy Market Information
power, it has also developed the Electronic Quarterly

Report, a more comprehensive public reporting system than

anything available outside an RTO. The EQR reports jurisdictional wholesale power sales, allowing for transparency

of physical, bilateral electric markets, although with a delay

of several months.

Improving Price Indices

Many energy market participants rely on price indices published in the trade press for basic price information. Price

indices are especially important to natural gas and parts of

the electric industry that have fairly strong bilateral markets

but no RTOs. Published indices are convenient for price takers, as long as they consider them reliable.

Price indices developed as a journalistic service—not as an

integrated part of a market structure. In practice, they were

not always reliable. Prices were sometimes based on few or

no trades and were subject to misreporting and other abuses.

These indices often did not convey enough information for

market participants to judge the validity of reported prices.

After the misreporting and wash-trading scandals revealed

in 2002 and the subsequent false-reporting cases by the

CFTC, market sources reported less information to the

index compilers, making the indices even less thorough and

reliable.1 Customers expressed a growing lack of confidence

in the indices. 

Commission Response. The Commission worked to

improve indices since early 2003. In July 2003, it issued a policy statement,2 defining both the reporting standards and

desirable characteristics of indices. The Commission sponsored two technical conferences and two index workshops

to discuss problems and encourage practical industry solutions. Many in industry worked to find and implement such

solutions.

Later in 2003, the Commission issued market behavior rules

that require adherence to certain basic standards by those

that report transaction data used in Commission-approved

tariffs.4 On May 5, 2004, the Commission released a comprehensive staff report3 gauging improvement. A follow-up

technical conference, in June 2004, featured 26 panelists

who assessed progress to date and offered recommendations

for further action. Another 29 parties supplied written comments. The Commission also issued an order on the future

monitoring of indices.5

Amount of Data Reported. Some index compilers have

noted an increase in the volume of fixed-price transactions

reported. Platts, for instance, found that volumes and transactions submitted for its monthly gas survey from February

through June 2004 increased by 35 percent or more, from

2003 levels. Volumes and transactions increased another 34

and 31 percent, respectively, in the first quarter of 2005 compared with a year earlier. In its daily gas survey, Platts reported that the number of natural gas transactions reported in

May 2004 was double that of November 2002 and that the

number reported in March 2005 was 34 percent higher than

a year earlier. In March 2005, the number of daily electricity

transactions reported had risen by 74 percent from a year

earlier.6

Process Improvements. The May 2004 staff report documented improvements in the data reporting process by comparing responses from the first industry survey in

September 2003 with the second survey in March 2004 (see

Figure 1). The survey showed improvement for each of the

key price-reporting standards in the 2003 policy statement:

• The percentage of companies that report to index 

State of the Markets Report • June 2005 37

Energy Market Information

0%

20%

40%

60%

80%

100%

Reporting by an

Independent Source

Annual Independent

Review

Having a Public Code of

Conduct

% of Responding Companies

Sep-03

Mar-04

Source: FERC Survey.

Fig 1: Process Improvements
38 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

compilers through a department that is independent

from the trading unit doubled to nearly two-thirds. 

• The percentage of companies conducting annual independent audits of their price reporting practices increased

from 5 percent to 58 percent.

• The percentage of companies with a public code of conduct for reporting transactions to index compilers rose

from 36 percent to 65 percent. 

Amount and Quality of Information Provided. Index

compilers began providing more information about activity

at pricing locations in response to industry interest. For

example, the 10xGroup, an affiliate of ICE, provides a service that includes the high, low, weighted average, and

change in price, along with the volume, number of trades,

and number of trading companies at each location for its

daily natural gas and electricity indices. 

In 2003, Platts and Natural Gas Intelligence Press Inc. began

to designate trading locations in their monthly gas indices as

Tier 1, Tier 2, and Tier 3 to provide an indication of the level

of activity at each location. A Tier 1 location has volume in

excess of 100,000 MMBtu, Tier 2 between 25,000 and

100,000 MMBtu, and Tier 3 fewer than 25,000 MMBtu. In

August 2004, both publishers increased the information provided by including the number of trades and volumes traded

in daily indices and for Tier 1 and Tier 2 monthly indices.

They also discontinued some illiquid price indices.

Other index publishers also responded. Energy Intelligence

Group began to provide volumes and the number of transactions as a result of the policy statement. Dow Jones began to

include the highs and lows with its day-ahead electricity

indices. Argus Media announced plans to add the number of

transactions to its hourly electricity indices. 

Finally, index publishers began to show which price reports

rely on data from actual transactions and which are estimates. Platts now notes with an asterisk and a footnote any

price that is an estimate rather than a weighted average of

reported trades. Other index publishers, including Energy

Intelligence Group, Powerdex, Argus Media, and Dow

Jones, also identify prices that are editorial estimates rather

than an average of actual transactions.7

While noting these improvements, however, the staff report

also expressed concern about the number of fixed-price

transactions in the month-ahead market and the degree of

industry reliance on index-based contracts rather than fixedprice contracts. The widespread use of monthly indices for

natural gas contracts may be especially problematic. Many

monthly indices rely on a few deals covering small volumes. 

Increase in Confidence. A survey conducted in March 2004

indicated that confidence in price indices averaged 6.9 on a

scale of 1 to 10. By industry group, the average ranged from

7.5 for gas utilities to 6.7 for marketers (see Figure 2). 

Moreover, conference participants noted that confidence

rose even higher after the release of the staff report that

detailed the findings of the March 2004 survey. For example,

the Process Gas Consumers Group stated that its “faith in the

price indices has been strengthened by the events of the past

two years.” EnCana Marketing (USA), Inc., said that it had a

“high degree of confidence in the prices that are being

reported and published.” The American Gas Association

pointed out that “confidence in price reporting had

increased markedly.” And the Electric Power Supply

Association said “both market liquidity and reporting has

increased and ... the markets’ confidence in indices has also

increased.” 8

Given the perceived improvement in the quality of gas and

electric indices, the Commission indicated it would continEnergy Market Information

0

10

20

30

40

50

60

70 

123456789 10

1% 1%

3%

12%

34%

22%

11% 12%

3% 1%

All respondents (average 6.93)

Marketers (average 6.74)

Industrial consumers (average)

Gas utilities (average 7.49)

Number of respondents 

Level of Satisfaction (1 - 10)

Source: FERC Survey.

Fig 2: Customer Satisfaction with Price Indices
ue to monitor the process but did not think mandatory

reporting was necessary. On November 19, 2004, the

Commission issued the “Order Regarding Future

Monitoring of Voluntary Price Formation, Use of Price

Indices in Jurisdictional Tariffs, and Closing Certain Tariff

Dockets.” The order:

• Directed staff to continue monitoring price formation,

including adherence to the standards in the policy 

statement;

• Reviewed the submissions of 10 index compilers and concluded that they substantially met the standards;9

• Adopted criteria that would allow a price index location to

be used in a jurisdictional tariff; and

• Applied the newly adopted criteria prospectively only.

Natural Gas Storage

The Energy Information Administration (EIA) releases its

Weekly Natural Gas Storage Report every Thursday at 10:30

a.m. Eastern Time. Storage inventories show changes in the

balance of supply and demand. The report is particularly

important because other, more directly relevant, statistics

(such as production levels) are not immediately available.

EIA’s report is the only government-issued, regularly published information that gives market participants a view of

current supply-demand dynamics in the natural gas industry.

The report affects the pricing of many transactions. Price

volatility for Nymex natural gas contracts increases immediately following the weekly release of the report, as traders

adjust their positions to reflect the new information. The

release of the EIA report can significantly affect other 

natural gas commodity prices, transportation, and market

and trading behavior. 

Given the importance of gas storage reports to markets

and the Commission’s charge to ensure that prices are just

and reasonable, FERC staff members actively monitor

storage reporting and its effect on gas markets. The

Commission undertook several oversight and enforcement

activities in 2004 to ensure accuracy and transparency of

storage information. 

Eliminating Sharing of Commercially Sensitive Data. In

2004, the Commission approved settlements with three

companies that communicated nonpublic, daily storage

injection, and withdrawal information to customers and

other market participants and, in one case, an affiliate, over

an extended period of time.10 The behavior violated the

Commission’s standards of conduct and rules prohibiting

undue preference. The information had commercial value,

helping recipients understand and anticipate gas price

movements. The information was also potentially helpful to

pipeline transportation users, because it provided insights

into pipeline operational dynamics and, on occasion, the

likelihood of curtailments. The settlements included civil

penalties, refunds to customers, and remedial actions to

prevent future improper exchanges of storage-related

information.

Technical Conference on Storage Reporting. Following

the settlements, the Commission invited the public to file

comments regarding enhanced storage reporting in advance

of an upcoming technical conference.11 The conference, on

September 28, 2004, explored whether the Commission

should require interstate pipeline companies and other

owners and operators of storage facilities to post each day’s

inventory levels electronically to increase transparency and

deter communication of nonpublic, storage-related 

information.

Those who filed comments, as well as those who participated in the September 28, 2004, conference, agreed that storage information is relevant to the market’s performance.

Discussion explored the potential value of publishing storage information daily to assist in decision-making and possibly reduce costs associated with volatility, thereby potentially increasing wholesale market efficiency. 

Views differed on whether or how to proceed. Some argued

that more frequent postings on pipeline websites would

mean that only larger firms could pay for services to collect

the information. Others contended that initial confusion

and problems with administration and accuracy of postings

would overwhelm any market benefit that a more frequent

data stream would offer. Still others questioned the merits 

of daily posting for a market they assessed as operating 

State of the Markets Report • June 2005 39

Energy Market Information
40 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

satisfactorily. Some expressed concern with the disaggregated and potentially incomplete nature of any proposed

reporting requirements.12 Finally, many argued that current

levels of posting by interstate operators already provided

adequate transparency.13

Investigating an Erroneous Storage Report. Weekly storage inventory reports that stray outside the range of expectations can have dramatic price consequences. On Wednesday,

November 24, 2004, the day before Thanksgiving, the EIA

released a weekly storage report at noon showing a 49 Bcf

withdrawal of natural gas from storage for the week ending

November 19. The price of natural gas futures contracts

immediately shot up, reacting to the sharp contradiction of

published reports that had forecast an announced withdrawal of 13 to 25 Bcf. The December Nymex gas futures

contract prices closed on November 24 at $7.98 per MMBtu,

up $1.18 on the day. This development was of particular

concern because it occurred during the expiration of the

December contract and therefore set the price for gas delivered that month.

The withdrawal was so unexpected that, in addition to the

price volatility, traders and analysts began to speculate about

a possible error in EIA’s reporting. Reflecting a widespread

belief that the report was wrong, the market began to fall.

From Monday, November 29, to Wednesday, December 1,

2004, the January contract dropped more than 50 cents.

EIA policy, meanwhile, stipulated that any revision would

not come until the following Thursday, the day of EIA’s next

regularly scheduled release. Also in keeping with EIA policy,

the revision would be unaccompanied by explanatory

detail. 

Accordingly, on December 2, EIA issued a report that included a revised number for the amount of natural gas withdrawn from storage for the week ending November 19. The

revised number was 17 Bcf—32 fewer Bcf than reported orignally. Nymex January futures prices dropped by $0.60 to

$6.81. 

On November 28, the Commission began to investigate the

event and subsequently helped identify the cause of the

error. The Commission estimated that the error and the

associated price increase may have cost market participants

from $200 million to $1 billion. The exact financial effect

was difficult, if not impossible, to determine because of the

many factors that influence gas pricing. 

Through their investigations, the Commission and the

CFTC sought to determine what happened and whether

individuals who knew of the mistake had used their knowledge to take advantage of the market responses. The initial

approach was to identify large withdrawals and Nymex

positions, and then to contact storage holders and operators

to ascertain their reasons for making withdrawals. 

Energy Market Information

Daily Inventory Levels

Weekly Inventory Levels

Daily Scheduled Volumes

Not Posted 

Source: Interstate pipeline bulletin boards.

Fig 3: Interstate Storage Posting Practices

$6.50

$6.70

$6.90

$7.10

$7.30

$7.50

$7.70

$7.90

$8.10

$8.30

$8.50

10:00 10:30 11:00 11:30 12:00 12:30 13:00 13:30 14:00

Price ($ /MMBtu)

EIA 

Report 

Issued 

Source: Derived from Nymex data.

Fig 4: Natural Gas Futures - November 24, 2004
Based on its investigation, the Commission was able to

assure market participants that it found no indication that

Dominion traders knew of the mistaken report or that

Dominion based any trading strategies on the incident. The

results indicated good standards of conduct training and

compliance at Dominion. An analysis of broader market

activity, especially on Nymex in coordination with the

CFTC, found no evidence of any trading strategy that

involved the erroneous report.

As a preventive measure, Dominion instituted reporting

process improvements that require a designated Dominion

manager to call to confirm the accuracy of all data that EIA

receives in storage reports from Dominion management

employees. 

Electric Quarterly Report—

Enhancing Market Oversight

The Commission requires public utilities and power marketers to file an Electric Quarterly Report 60 days after the

end of each quarter.14 An EQR must summarize the contractual terms and conditions in all jurisdictional sales service

agreements (including market-based power sales, cost-based

power sales, and transmission service) and set out detailed

transaction information for power sales (and merchant

transmission negotiated rate transactions) during the most

recent calendar quarter. Data for each sale are to include the

identity of the seller and purchaser; the product sold (e.g.,

energy, capacity); the exact date and time of each sale; key

terms of each sale (e.g., whether it was short- or long-term,

peak or off-peak, hourly or weekly); and the quantity, rate,

and amount charged. Filing EQRs quarterly is required to

maintain market-based rates. The EQR makes part of the

overall physical electric market fully transparent after the

fact. In doing so, the report enhances regulatory oversight. 

The EQR is not fully comprehensive. It excludes:

• Generation to serve native load;

• Sales by federal authorities such as Tennessee Valley

Authority (TVA) and Bonneville Power Authority (BPA);

• Sales by other public entities;

• Sales within the Electric Reliability Council of Texas

(ERCOT); and

• Sales by qualifying facilities (QFs) under QF contracts. 

FERC has worked to improve the EQR by introducing and

improving filing software, directing filers to review their

submissions for errors, conducting EQR workshops, streamlining entries, and standardizing control areas. 

Most recently, staff implemented several validation checks.

In an ongoing effort to improve data quality, staff updated

“flags” to detect such incorrect entries as disaggregated

transaction data, mistakes in reporting affiliate status, suspiciously high or low prices, trading companies not reporting

book outs, and data inconsistent with other filings (e.g.,

Form 1, 10-K). Such measures have improved quality

although, in some cases, the new stringency has led to

increases in late filings (see Figure 5).

Checks for outlying data have reduced identified errors in

reported data (see Figure 6).

FERC continues to improve EQR data collection and to

make requirements clearer for respondents. As of the end of

2004, 991 respondents at 1,165 companies reported approximately 5.5 million lines of transaction data each quarter.

The EQR data provide important insights into the bilateral

physical power market, which otherwise remains largely

opaque. Omissions remain a concern, as sales by nonjurisdictional entities (detailed earlier) are not included in the

data.

Conclusion and Future Issues

Cost-effective provision of timely, reliable, and pertinent

information is crucial to the health of all markets. Different

market participants require different kinds of information.

The Commission supports the development of market

information systems that meet diverse needs. It has shown

its willingness to help develop practical approaches to

improving information quality and access to all participant

types. 

The Commission also continues to develop its own information resources to monitor energy markets better.

State of the Markets Report • June 2005 41

Energy Market Information
42 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Information resource development includes maintaining

access to many publicly available information sources, developing data collections (such as the EQR), and obtaining

more detailed information when needed in particular situations or individual cases. 

Energy markets face further information challenges.

Among the most important of these are:

The jurisdictional split between physical and financial

trading. The CFTC regulates financial trading, whereas the

Commission regulates (most) physical trading. Because

market players can structure most transactions to be either

physical or financial, it can be difficult for either the

Commission or the CFTC to get a picture of the interconnected market.

The jurisdictional splits within the physical side of the

power industry. The Commission does not regulate municipalities, cooperatives, and other public electric entities. As a

result, it is very difficult to get fully comprehensive information about the overall physical market.

The different market platforms within the electric

industry. Much of the electric industry uses RTO market

structures that are similar. Other parts of the industry have

fairly strong bilateral markets, as does natural gas. These

structures tend to produce information that is less 

transparent than that of an RTO, but still allows a fairly wide

range of markets to develop. Other regions (e.g. the

Southeast) tend to have very little information available and

therefore see only rudimentary markets. The challenge,

therefore, is twofold: how to integrate the information

aspects of different functioning market platforms (such as

natural gas and electric RTOs) and how to develop the information infrastructure for regions that barely have functioning markets today.

Energy Market Information

0

1

2

3

4

5

6

Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

2002 2003 2004

Recored Count (millions)

Key Quality 

Checks 

Implemented

Timely filing

Late Filing*

Blanket filing 

extensions 

issued

Source: FERC EQR filings.

Fig 5: 2002-2004 EQR Filings

0

500

1,000

1,500

2,000

2,500

Q1 04 Q2 04 Q3 04 Q4 04

Transaction Records

Source: FERC EQR filings.

Fig 6: 2004 EQR Reporting Errors
State of the Markets Report • June 2005 43

Energy Market Information

1 Events since the bankruptcy of Enron in late 2001 have reduced

confidence in price indices. In 2002, the Commission’s Western

Markets Task Force investigated the role that natural gas indices

played in the high prices charged for electricity in California in

2000–01. The Final Report on Price Manipulation in Western

Markets, issued March 2003 in Docket No. PA02-2-000, determined that employees of several companies reported false information to publishers of price indices in an effort to skew indices

in favor of their trading activities positions (short or long) taken

in both the physical and financial markets. Subsequently, the

CFTC and certain U.S. attorneys also initiated investigations into

false price reporting that resulted in significant civil penalties on

a number of energy companies and indictments of some individuals.

2 Policy Statement in Natural Gas and Electric Price Indices, 104

FERC 61, 121 (2003).

3 Report on Natural Gas and Electricity Price Indices, Docket Nos.

PLO3-3-004 et al. May 5, 2004.

4 Order Amending Market-Based Rate Tariffs and Authorizations,

105 FERC 61,218 (2003), reh’g denied 107 FERC 61,175 (2004),

and Order No. 644, Amendment to Blanket Sales Certificates,

FERC Stats. & Regs. 31,153 (2003), reh’g denied 107 FERC

61,174 (2004).

5 Order Regarding Future Monitoring of Voluntary Price Formation,

Use of Price Indices in Jurisdictional Tariffs, and Closing Certain

Tariff Dockets (2004) 109 FERC 61, 184.

6 Platts comments (June 14, 2004) at 1–3 and discussion with staff

on April 6, 2005. Platts also noted that its gas survey now has

more than 60 contributors and that all but one of the top 12 trading companies are reporting their natural gas transactions. Id. at

3–4.

7 Platts Technical Conference Comments (June 14, 2004).

8 Ibid.

9 Argus Media Inc., Bloomberg LP, Btu/Data Transmission

Network, Dow Jones and Co., Energy Intelligence Group, Natural

Gas Intelligence Press Inc., IntercontinentalExchange Inc. (10x),

Io Energy LLC, Platts, and Powerdex Inc.

10 The Commission issued an order in Docket IN04-2-000 approving three stipulation and consent agreements. The agreements

state that the signatories—two interstate, natural gas pipeline

companies and one local distribution company—communicated

their respective, nonpublic storage inventory information to customers or industry participants. 

11 Enhanced Reporting of Natural Gas Storage Inventory

Information, Docket No. AD04-10-000. 

12 Technical Conference (September 28, 2004). 

13 Analysis of informational postings. Daily scheduled does not

always include no-notice storage activity.

14 Revised Public Utility Filing Requirements, Order No. 2001, 67 FR

31043, FERC Stats. And Regs. 31,127.

Disclaimer: This report contains analyses, presentations, and conclusions that may be based on or derived from the data sources cited, but

do not necessarily reflect the positions or recommendations of the data

providers. 

Endnotes
44 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Energy Market Information
I

n November 2003, the Commission issued Market Behavior Rules to fill a

void in the regulation of market-based trading activity.1 In its order, the

Commission also required that the effectiveness and consequences of the

behavior rules be evaluated annually in the State of the Markets Report. 

To date, indications from the wholesale energy markets

are that the behavior rules are effective and achieving

their purpose. The attention being paid by companies

to the behavior rules, evidence of widespread training of

market participants, and the relative absence of 

complaints indicate that the behavior rules have had an

overall beneficial effect on wholesale energy markets.

Market participants have expressed concerns, however,

about the clarity of the rule related to market manipulation. A few parties described how concern regarding

this rule is hindering innovation and reasonable but

aggressive postures by company traders.

MARKET BEHAVIOR RULES:

EFFECTIVENESS REVIEW

State of the Markets Report • June 2005 45
46 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

The Market Behavior Rules

The behavior rules resulted from the Commission’s investigation of trading activity in western markets during 2000-

2001, which uncovered a number of trading schemes

intended to take advantage of the then-existing electricity

market in California. The Commission also discovered

abuses in reporting of natural gas prices to price index publishers for purposes of manipulating price indices. 

The behavior rules were adopted to establish clear guidelines

applicable to the conduct of market-based rate sellers in

wholesale power markets and to pipelines and companies

engaged in natural gas transactions under blanket certificate

authority in natural gas markets. The rules also provide a

balanced approach to remedies for anticompetitive behavior

or market abuses.

The behavior rules for market-based trading of electricity

address six topics:

Rule 1, Unit Operation: Requires sellers to operate and

schedule generating facilities, undertake maintenance,

declare outages, and commit or otherwise bid supply in a

manner that complies with the rules and regulations of the

applicable power market. 

Rule 2, Market Manipulation: Prohibits actions and transactions without a legitimate business purpose that are

intended to, or foreseeably could, manipulate market prices,

conditions, or rules. Specifically prohibits certain types of

conduct, such as wash trades, transactions based on false

information, transactions to create and relieve artificial congestion, and collusive transactions.

Rule 3, Communications: Maintains that sellers must provide accurate and factual information and not submit false

or misleading information, or omit material information,

in any communication with the Commission, market monitors, regional transmission organizations (RTOs), independent system operators (ISOs), or similar entities, under a

due diligence standard.

Rule 4, Reporting: Provides that if sellers report transactions to price index publishers, they must provide accurate

and factual information in accordance with the standards of

the July 2003 Policy Statement on Natural Gas and Electric Price

Indices.2 

Rule 5, Record Retention: Requires sellers to retain for

three years all data and information necessary for the reconstruction of the prices they charge and the prices they report

for use in published price indices.

Rule 6, Related Tariffs: Prohibits sellers from violating or

colluding with another party in actions that violate seller’s

tariff code of conduct or applicable standards of conduct. 

The behavior rules applicable to market-based rate sellers of

electricity became effective December 17, 2003, and were

automatically deemed incorporated into the tariff of every

seller with market-based rate authority. All such sellers were

directed to file the behavior rules in prescribed form in their

tariff, with the effective date of December 17, 2003.3

For natural gas wholesale transactions subject to the

Commission’s jurisdiction, the applicable rules (parts of

Rule 2; Rule 4 and Rule 5) have been incorporated in 18 CFR

§§ 284.288 and 284.403, making them applicable to interstate pipelines and to all holders of blanket certificate

authority to engage in sales of natural gas for resale subject to

the Commission’s jurisdiction. The behavior rules applicable to natural gas wholesale transactions became effective

December 23, 2003.

To provide balance between enforcement of rule violations

and certainty for past energy transactions, complaints alleging violations of the behavior rules must be filed with the

Commission within 90 days of the calendar quarter in which

the violation is alleged to have occurred, or within 90 days of

the time the complainant knew or should have known of

the behavior. Similarly, if the Commission becomes aware

of potential violations of the behavior rules, it must take

action, such as initiating an investigation, within 90 days of

learning of the alleged conduct. The principal remedy for a

violation of the behavior rules, in addition to any other

applicable remedies, is disgorgement of unjust profits from

the violation. Given the evolving energy markets, the

Commission also required that the effectiveness and consequences of the behavior rules be evaluated in the annual

State of the Markets Report.

Market Behavior Rules: Effectiveness Review
Reaction to Behavior Rules

Many parties presented views and concerns to the

Commission on the proposed rules, and the Commission

made several modifications to the proposed rules in

response to these comments. Since issuance of the final

rules, however, direct comments to the Commission have

been limited to requests for rehearing, all of which were

denied. 4

The Commission adopted rules that attempt to combine

adequate notice of prohibited conduct while retaining

enough flexibility to address facts and circumstances not currently envisioned. It was the Commission’s expectation that

future cases will present concrete circumstances in which

the behavior rules are applied, permitting the Commission

to highlight specific prohibited conduct on a case-by-case

basis.5 At the present time, however, no cases have yet

reached the Commission for decision. In addition, no formal complaints have been filed with the Commission alleging violations of the behavior rules.

A common theme expressed by industry participants is that

Behavior Rule 2, dealing with market manipulation, is

vague. As noted earlier, Behavior Rule 2 bars actions or

transactions without a “legitimate business purpose” that

are intended to or foreseeably could manipulate market

prices, conditions, or rules. The Commission provided specific examples of actions that violate Behavior Rule 2 (such

as wash trades or creation of artificial congestion) and

explained that if a transaction were undertaken to provide

service to a buyer with rates, terms, and conditions disciplined by competitive forces, the transaction would have a

legitimate business purpose.6

This has given a degree of guidance to the industry, although some participants may find

uncertainty in specific circumstances and others may adopt

a cautious (or overly cautious) approach to new trading

strategies until more information about the scope and

meaning of the behavior rules is available.

We have received reports that market participants have

begun incorporating the behavior rules into their training

programs and are providing guidance for trading personnel

and managers of market activity. This is an essential step to

translating the principles of the Behavior Rules into specific

guidance for the personnel involved in day-to-day market

activities. 

Notification Concerning Price Reporting

Behavior Rule 4 required that sellers notify the Commission

whether they report prices to publishers of price indices in

accordance with the standards of the Price Index Policy

Statement and to report any subsequent change in reporting

status. The Commission received notices on behalf of 756

companies. While most notices stated the companies were

not reporting energy trade data to price index publishers in

accordance with the Policy Statement standards, many of

the companies that notified the Commission they are

reporting are among the most active traders. Moreover, subsequent filings of update notices indicate that more companies are now reporting transaction data. Consistent with

this, the volumes of transactions reported by price index

publishers indicates a continuing increase in the number of

transactions being reported, thus providing additional price

information to interested market participants (see essay on

“Improving Energy Market Information”).

Effectiveness of Behavior Rules

On May 6, 2005, the Commission hosted a technical conference and workshop on both the standards of conduct and

the behavior rules. Speakers representing segments of

industry addressed the behavior rules and noted that, while

some confusion remains about the scope of Behavior Rule 2,

companies are providing training to employees and understand the importance of common ground rules for market

activity. Feedback from conference participants indicates

that most companies have provided training in the behavior

rules and that many companies have made changes in their

market operations as a result of the adoption of the behavior

rules. When asked whether the behavior rules have had a

positive or negative impact on wholesale energy markets, a

majority of those responding said that the behavior rules

have had a “somewhat beneficial” effect.

The attention being paid by companies to the behavior

rules, evidence of widespread training of market participants, and the absence of complaints indicates that the

behavior rules have had an overall beneficial effect on

State of the Markets Report • June 2005 47

Market Behavior Rules: Effectiveness Review
48 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

The Market Behavior Rules

The behavior rules resulted from the Commission’s investigation of trading activity in western markets during 2000-

2001, which uncovered a number of trading schemes

intended to take advantage of the then-existing electricity

market in California. The Commission also discovered

abuses in reporting of natural gas prices to price index publishers for purposes of manipulating price indices. 

The behavior rules were adopted to establish clear guidelines

applicable to the conduct of market-based rate sellers in

wholesale power markets and to pipelines and companies

engaged in natural gas transactions under blanket certificate

authority in natural gas markets. The rules also provide a

balanced approach to remedies for anticompetitive behavior

or market abuses.

The behavior rules for market-based trading of electricity

address six topics:

Rule 1, Unit Operation: Requires sellers to operate and

schedule generating facilities, undertake maintenance,

declare outages, and commit or otherwise bid supply in a

manner that complies with the rules and regulations of the

applicable power market. 

Rule 2, Market Manipulation: Prohibits actions and transactions without a legitimate business purpose that are

intended to, or foreseeably could, manipulate market prices,

Market Behavior Rules: Effectiveness Review

1. Order Amending Market-Based Rate Tariffs and Authorizations,

105 FERC 61,218 (2003) (Behavior Rules Order), reh’g denied,

107 FERC 61,175 (2004) (Behavior Rules Rehearing); Order No.

644, Amendment to Blanket Sales Certificates, FERC Stats. &

Regs. 31,153 (2003), reh’g denied, 107 FERC 61,174 (2004).

2. 104 FERC 61,121 (2003)(Price Index Policy Statement). See Essay

in “Improving Energy Market Information.”

3. Order Clarifying Prior Notice, 105 FERC 61,277 P 9 (2003).

4. The behavior rule orders now are on appeal. Cinergy Serivces

Inc., et al. v. FERC, Nos. 04-1168, et al. (D.C. Circuit, filed May 28,

2004).

5. Behavior Rule Order 172.

6. Behavior Rule Rehearing 43.

Disclaimer: This State of the Market report contains analyses, presentations, and conclusions that may be based on or derived from the data

sources cited, but do not necessarily reflect the positions or recommendations of the data providers.

Endnotes
ELECTRIC POWER MARKETS IN 2004

State of the Markets Report • June 2005 49

This State of the Markets Reportcontains an overview of electricity markets and individual 

profiles of 10 major electric regions: New England, New York, PJM, the Midwest (MISO

and MAPP), the Southeast, SPP, ERCOT, the Southwest, the Northwest, and California.
50 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Electric Power Markets National Overview

NATIONAL OVERVIEW

Nationally, four keys to understanding U.S. power markets in 2004 were:

Electric markets remained essentially regional. Market institutions continued to differ greatly among

regions, as did resource mixes and ways of addressing transmission congestion. During 2004, the most notable change

was the further development of Regional Transmission Organizations (RTOs) in several regions. In regions without

RTOs, independent generators continued to complain about lack of equal access to the grid. 

Average electric power prices rose in almost all regions. New York, New England, and Texas (regions with

RTOs that depend largely on natural gas) had relatively small increases. Regions that depend heavily on eastern coal

saw the highest price increases. This pattern reflected the relative price increases of the fuels used in each region.

The country as a whole had overbuilt generating capacity, but was underinvesting in load pockets.

Regions without RTOs provided few price signals to give an incentive to invest in load pockets. In RTO regions, price

signals within load pockets were often insufficient to provide an incentive to build, either because of administrative

procedures that would mitigate prices or because of a lack of location specific pricing. Even in New York City, which

had a stronger price signal than other load pockets, state agencies were building much of the new capacity that will

eventually come on line. Transmission investment had increased in recent years, but large-scale upgrades remained

hard to site and build.

Financial institutions emerged as major players in the electric industry. In 2004 alone, hedge funds

and lenders acquired 4.7 percent of generating capacity in the United States. Financial trading overall increased 

significantly in energy.

Northwest

Southwest

California

ERCOT

SPP

PJM

Midwest

Southeast

New York

New England
The most important structural feature of the electric power

market in the United States is its regional diversity—in

resource mix, consumption patterns, and market institutions. The resource mix for power generation differs from

region to region (see figure 1). The most significant differences are the importance of hydropower in the Northwest

and the relative mix of natural gas generation compared

with coal or nuclear steam generation in other regions. 

Overall consumption for the country totaled 3,711,667

GWh in 2003 and increased to 3,827,325 GWh in 2004.1

Market institutions also differ among regions. In

the East, California, and Texas, regional transmission organizations (RTOs) operate the transmission

grid and the basic spot market for power. During

2004, the Midwest and the Southwest Power Pool

(SPP) moved toward adopting RTO markets, with

the Midwest considerably more advanced than SPP.

By the end of 2004, regions accounting for 68 percent of all economic activity in the United States had

chosen the RTO option.2

In the West, long-distance electric transmission and

trading are essential for the entire region. Fairly

deep and liquid bilateral spot markets exist at 10 to

12 locations inside and outside California. These

trading locations provide price discovery for the

markets outside California and supplement the California

Independent System Operator’s (CAISO) balancing market

within California. 

Southeastern bilateral markets have few liquid trading

points, except for a moderately liquid index for power moving into Entergy. Southeastern markets have little or no

transparency, and serious concerns remain about access to

transmission for independent generators.

Table 1 summarizes the market services available in each

region in 2004.

State of the Markets Report • June 2005 51

Electric Power Markets National Overview

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

New England

New York

PJM

Midwest

Southeast

SPP

ERCOT

Northwest

Southwest

California

Share of Regional Total (%)

OTHER (Mostly

Renewables)

GAS and/or OIL

CT

GAS and/or OIL

ST

GAS and/or OIL

CC

COAL ST

NUCLEAR

HYDRO

Source: Derived from data from Platts data. See Source Note 1.

Fig 1: 2003 Capacity by Fuel and Prime Mover

Regional Diversity

1 Systemwide 2 Locational 3 Systemwide with the exception of the Northern Illinois control area.

Real-time Day-ahead Virtual Ancillary Financial Capacity Associated 

market market Bidding services transmission (UCAP) financial

markets rights markets markets

(RTO/ISO) Bilateral (RTO/ISO) Bilateral (RTO/ISO) (RTO/ISO) (RTO/ISO) (RTO/ISO)

New England       1 

New York       2 

PJM       3 

Midwest  

Southeast  

SPP  

ERCOT    

Northwest  

Southwest  

California     

Table 1: Wholesale Electric Markets in 2004

05

06

05 05 05
1 An active market is defined as one that currently provides a historical price series.

2 Losses allocated to market participants based on a pro-rata share of total transmission losses.

3 Allocated to sellers using generation meter multipliers, which reflect scaled marginal losses.

4 Regulation is cost-based outside of MAAC.

5 Non-spinning reserves are derived from market-based offers.

6 Units needed for VAR taken out-of-merit.

7 Fixed monthly Mvar payment plus opportunity cost.

8 RFP procurement process.

9 CAISO has cost-based contracts for RMR.

10 No day-ahead energy markets; economic dispatch used in real-time balancing markets.

52 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Electric Power Markets National Overview

Existing Projected for ‘05 or ‘06  Cost-Based  Other

Services Provided ISO-NE NYISO PJM MISO SPP ERCOT CAISO

Bilateral transactions 

Active online physical trading (1) 

Active online financial trading (1) 

Real-time energy market 

Locational energy price 

Hourly energy price 

Congestion price 

Losses price 2 3

Day-ahead energy market 

Locational energy price 

Hourly energy price 

Congestion price 

Losses price 2

Ancillary services market   

Regulation service market 4   

Operating reserves market 5   

Reactive power market 6 7    

Black start market    8 

Financial transmission rights 

Capacity market 9

Regional transmission scheduling 

Regional economic dispatch 10 10

Regional transmission planning 

Regional interconnection process 

Independent market monitor 

Mitigation 

RTO Spot Markets Table 2: RTO Market Characteristics in 2004 

All RTOs in current operation:

• Dispatch the generators in their 

systems and operate at least one

short- term market that prices energy, 

congestion, and losses—Eastern RTOs

all offer day-ahead and real-time markets and California and Texas offer

real- time market alone; 

• Use some form of locational pricing,

though the level of granularity differs

from locational marginal pricing

(LMP) in the northeastern RTOs to

Texas’ and California’s zonal system;

and

• Have independent market monitors.

In 2004, the Midwest Independent

System Operator (MISO) and the

Southwest Power Pool (SPP) also had

market monitors in place in preparation for starting their markets in 2005

and 2006, respectively.

Table 2 shows the different variety of

services available within each RTO.

Overall, RTO markets offer efficient

systems of economic dispatch, price

transparency for market transactions,

and methods for addressing possible

abuses of market power. Each RTO

market continues to find it necessary to

administratively adjust outcomes with

mitigation authority. In many cases,

other markets have grown up around

the RTO markets. PJM West, for

example, is among the most heavily

traded bilateral markets and Nymex

offers a futures contract for PJM.

Similarly, ERCOT and both NP-15 and

SP-15 in California are among the most

heavily traded bilateral markets in the

country. In contrast, visible bilateral

trading in New York City has essentially disappeared over the past 2 years.

06

06

06

06

06

05

05

05

05

05

05

05

05

05

05

05

05 06

05 06
State of the Markets Report • June 2005 53

RTO Spot Markets

In 2004, the areas covered by RTOs expanded. Figure 2

shows the current configuration:

• Several large service territories joined PJM, which now

includes many areas in Virginia, West Virginia, Ohio,

and Illinois as well as its historical region in the midAtlantic. The area now in PJM covers about 18 percent

of total electricity consumption in the United States.

• MISO continued developing its day-ahead and real-time

markets for deployment in 2005. 

• The Commission approved RTO status for SPP. It will

begin with a balancing market (planned for early 2006). It

has already set up a Regional State Committee (RSC) to

facilitate regional transmission planning and oversight.

• The Commission approved the Independent System

Operator for New England (ISO-NE) for RTO status, 

effective in 2005.

Other Spot Markets

In the desert Southwest and the Pacific Northwest, large

volumes of energy have long traded in bilateral markets.

The two most liquid points are Mid-Columbia (Mid-C) in

the Northwest and Palo Verde in the Southwest. Other

pricing points with significant quantities of visible bilateral trading include the California-Oregon Border (COB)

and Mead.

In some ways, bilateral power markets in the West resemble natural gas markets more than they do RTO markets.

They do not provide the same level of services or information as RTOs. Nonetheless, many of them appear to be

reasonably liquid and transparent. One indication of the

health of bilateral markets in the West has been the length

of contracts one can obtain on the open market. Some

services advertise deals going out as long as 12 years—3

years is more common in the East—indicating a degree of

confidence in bilateral western markets.

CAISO

SPP

ERCOT

MISO

PJM

NYISO

ISO NE

Electric Power Markets National Overview

Fig 2: RTO Configurations in 2004
54 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Electric Power Markets National Overview

Region $/kW-yr

NYISO NYC $135.25

NYISO Rest of State $16.65

PJM $5.38 for CT/ $5.24 for CC

ISO-NE $0.36

Source: PJM Interconnection, NYISO, and ISO-NE market monitoring units.

Table 3: Net Revenues from Installed Capacity

Bilateral markets in the Southeast tend to be much less liquid and more opaque than in other regions. The number of

bilateral trades reported at the Into Entergy trading point is

higher than at any other southeast point. Traders report few

trades for other points in the Southeast and almost none for

Florida. 

Approaches to Congestion

Transmission congestion is a central feature of the electric

power industry. It arises when there is not enough transmission available to deliver less costly power into an area that

then must run more costly generators instead. The electric

industry in the United States addresses transmission 

congestion mainly in four ways.

• Locational Marginal Pricing (LMP). In New England,

New York, and PJM, the RTOs use LMP to set a value for

power at each node in the grid. Security-constrained economic dispatch ensures efficient use of transmission and

determines which generators must change their operations to account for transmission congestion. This process

yields LMPs where price differences among nodes indicate the costs of congestion. Beginning in 2005, MISO

will join the eastern RTOs in using LMP to address 

congestion.

• Zonal Prices. ERCOT’s and California’s zonal prices represent a hybrid approach. Zonal pricing uses separate

aggregate prices for each zone aggregate. Such a system

shows market participants the incidence and value of congestion among but not within zones, reducing transparency.

• Transmission Loading Relief (TLRs). TLRs are orders to

customers to limit their transactions and thereby reduce

loads on particular transmission lines. Operators use

TLRs to limit the use of transmission lines in some regions

where LMP does not ration capacity. TLRs relieve 

congestion, but they are administrative, not market

mechanisms. As a result, TLRs indicate where congestion

occurs but give little indication of how much cost the

congestion causes. In 2004 (and until MISO’s markets

began operation in 2005), TLRs were the primary method

to address congestion in the Midwest. Entergy, SPP, and

TVA also make wide use of TLRs.

• Redispatch. In some regions, system operators redispatch their systems to accommodate congestion without

giving any clear signal as to how much congestion has

occurred or how much it is worth. The Southern

Company uses this approach, as does much of the West. 

Capacity Markets

RTOs have complemented their energy markets with

installed capacity markets. RTOs use capacity markets to

ensure that load-serving entities pay for the cost of having

enough capacity available to meet reserve margin requirements. RTOs intend that capacity markets will provide an

additional stream of revenue to generators that can make it

financially possible to invest in new generating plants when

needed.

As estimated by the PJM, the New York Independent

System Operator (NYISO), and ISO-NE market monitors,

net revenues from installed capacity (see Table 3) varied by

region in 2004. Except in New York City, the 

revenues in capacity markets were generally low, particularly

in New England. 
State of the Markets Report • June 2005 55

Electric Power Markets National Overview

Average Spot Price Levels

Most market participants use spot markets for a small fraction of their purchases and sales. (The volatility of electricity

markets makes heavy reliance on the spot market problematic for many players.) Nonetheless, healthy spot markets

are critically important for the functioning of all wholesale

power markets. Spot markets establish the value of power at

each time period as short as 5-minute intervals. Spot markets provide price signals that:

• Enhance short-term decisions—power traded at the margin

ensures that the most efficient mix of generators provides

power to those who most value it, without 

necessarily changing the total bills for most customers; and

• Influence the value of longer term contracts and expectations for future spot prices. 

All competitive electric markets ultimately rest on wellfunctioning spot markets, either bilateral or as part of RTOs.

However, spot markets in some regions, in 2004, remained

opaque with no RTO markets and few or no bilateral trades

reported to index publishers. These regions include imminent RTO regions SPP and the MAPP and MAIN regions of

MISO, as well as the non RTO Southeast. As a result of the

underlying nature of the markets in these regions, any pricing information is at best indicative of the regional prices,

although the published indices are the best pricing information available publicly. Price transparency in MISO and SPP

should improve with the implementation of RTO markets.

Pricing

Electric prices for on-peak periods increased for most major

pricing points around the country between 2003 and 2004.

The levels of price increases varied by region as shown on

Figure 3. On-peak prices for pricing points in Texas, New

York, New England, PJM, the desert Southwest and the

Great Plains, rose by 6 percent or less. Pricing points in other

regions—the Southeast, the industrial Midwest, and much

of the West Coast—increased more than 10 percent. Some

areas (Southern, VACAR, Cinergy, and ECAR North)

showed increases of more than 15 percent.

In the Eastern Interconnection and Texas, the lowest onpeak price increases came in areas where natural gas is 

typically the marginal fuel. In the West, California, and

Northwest, prices moved together, maintaining $4 to $5

gaps between Mid-Columbia and the California-Oregon

border and again between COB and northern California.

Off-peak prices generally increased more on a percentage

basis in 2004 than on-peak. Much of this increase was due to

coal price increases.

Two key factors often drive electric power prices—weather

and input fuel prices. In 2004, weather extremes were rare

and input prices increased.

Weather

Average winter temperatures in 2003–2004 were about normal for the nation—cooler on the East Coast, warmer in the

Midwest. The summer was the ninth coolest on record

nationally. Spring and fall were both warmer than usual.

Overall mild weather, particularly in the summer, lowered

demand and probably moderated price increases. This pattern also made severe price events less likely. 

The year’s two major price events both occurred in the

Northeast in the winter. The first was a severe weather

episode that affected New England and put the combined

markets for natural gas and electric power under unusual

stress (see Figure 4). This episode produced the largest differences between day-ahead and real-time prices during the

year for any RTO market because market participants failed

to anticipate either the severity of the weather on the first

day or the rapidity with which normal conditions would

return on the next day. 
56 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Electric Power Markets National Overview

$0

$20

$40

$60

$80

$100

$120

$140

Jan

Feb

Mar

Apr

May

Jun

Jul

AugSep

Oct

NovDec

$/MWh

Platts Mass Hub

ICE Mass Hub

ISO Mass Hub

Platts: $315

ICE: $174

ISO: $373

Source: Derived from ISO-NE data. See source note 3.

During the New England cold snap, market participants Fig 4: New England Daily Average On-Peak Prices

found it difficult to coordinate their activities in the natural gas and electric markets (see separate essay). Even so,

on balance, the market worked well during the event.

Prices rose and both the power and gas markets cleared

without curtailments or blackouts. As soon as the severe

weather passed, prices returned to normal levels.

The second incident occurred in December and affected

New York and New England. The stresses were not as

severe as the January incident. Again, the markets

worked well, clearing without physical disruption and

returning prices to normal levels when the weather

returned to normal.

In the West, hydro conditions were somewhat worse

than normal. Mild summer temperatures helped avert

major price events.

Northwest

California

Southwest

Midwest

SPP

ERCOT

Southeast

PJM

New York

New England

Prices 2004

Prices 2003Prices 2003

Percentage change

Mid-Columbia

$44.54

$40.73

9.3%

COB

$49.09

$44.49

10.3%

$54.46

$49.13

10.9% NP-15

SP-15

$55.20

$51.25

7.7%

$51.91

$50.65

2.5 %

Mead

$50.09

$49.10

2.0%

Palo Verde

$47.32

$46.49

1.8%

ERCOT

$50.51

$48.55

4.0%

Four Corners

$45.19

$41.66

8.5% SPP

$45.90

$43.29

6.0%

MAPP S

$47.06

$45.18

4.2%

MAPP N $47.94

$43.14

11.1%

MAIN N

$42.03

$37.11

13.2% NI Hub

$45.76

$41.47

10.3%

Entergy

$44.23

$38.90

13.7%

TVA

$58.31

$52.21

11.7%

Florida

$48.67

$41.55

17.1%

Southern

$43.31

$37.57

15.3%

Cinergy

$51.10

$48.49

5.4% PJM West

$45.58

$38.41

18.7%

ECAR N

$52.49

$51.36

2.2%

$61.74

$61.73

0.0%

$61.47

$59.05

4.1% NYISO A

NYISO G

Mass Hub

$76.63

$77.82

-1.5%

NYISO J

$48.27

$41.60

16.0%

VACAR

MAIN S

$42.85

$38.43

11.5%

Source: Derived from Platts Megawatt Daily and Dow Jones data. See source note 2.

Fig 3: Electric Regions with Pricing Nodes On-Peak Prices ($/MWh)
State of the Markets Report • June 2005 57

Electric Power Markets National Overview

Effects of Input Prices: 

Natural Gas, Coal, and Emission Allowances

A major factor contributing to the pattern of electricity price

increases was the relative price of fuel and other inputs. Led

by oil, natural gas prices continued to rise in 2004, by about

8 percent over 2003. Gas prices rose slightly less in the

Northeast (in percentage terms) than elsewhere (see Table

4). In the Northeast and Texas, average on-peak power

prices rose less than natural gas prices did (minus 1.5 percent

in New York City to 5.4 percent in PJM West). In California

and Florida, on-peak power prices rose somewhat more

than natural gas prices (7.7 percent to 11.7 percent).

Coal prices present a more complex story than natural gas

prices. Nationally, the EIA reports that average coal prices

increased by about 6 percent.3 However, the national average coal price includes a large percentage of coal that moves

under long-term contracts with fixed price terms. In looking at spot market prices for electric power, the more important coal price is the spot coal price because a generator could

sell the coal on the spot market instead of generating power.

Increases in spot coal prices varied by region. Some key 

eastern coal prices rose by 69 percent. For western coal from

the Powder River Basin, the spot price increased 6 percent. 

Finally, prices for emission allowances (effectively another

key input for many coal-fired generators) rose significantly

through the year. This pattern of coal and emission

allowance prices is consistent with the observed small electric price increases in areas where plants typically use western coal in the marginal generating unit. Greater price

increases are to be expected where eastern coal and associated emissions allowances are more often on the margin. 

Input 2003 Price 2004 Price Change

Natural Gas ($ per MMBtu)

Henry Hub $5.44 $5.85 8%

Southern California $5.08 $5.51 8%

New York $6.45 $6.81 6%

Coal ($ per ton)

Central Appalachian (Eastern) $32.19 $54.39 69%

Powder River Basin (Western) $6.16 $6.56 6%

SO2 Allowances ($ per ton) $175.53 $436.31 149%

Oil

WTI (Crude - $ per barrel) $31.06 $41.51 34%

Residual Fuel, New York ($ per barrel) $27.47 $27.95 2%

Distillate Fuel, New York ($ per gallon) $0.85 $1.12 32%

Source: Derived from Platts, Bloomberg, and Cantor Fitzgerald data. The SO2 Allowances are based off of monthly averages.

Table 4: Change in Input Price 2003–2004
58 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Table 5 shows average 2004 power prices

both on-peak and off-peak for pricing

points around the country. Consistent

with fundamental market drivers, both

on-and off-peak price increases were

greatest for regions and times that were

most likely to depend on eastern coal for

the marginal generating unit—Virginia,

Southern, and the eastern Midwest. Price

increases were relatively low for coalburning regions further west—the Great

Plains and the Southwest. 

The off-peak effects of eastern coal prices

were more pronounced than the on-peak

effects. Coal is more often on the margin

in off-peak periods. (Spot electric prices

tend to track the running costs of the online unit with the highest operating costs.

The operating costs are mostly from fuel

and emissions allowances.) Many pricing

points in the Southeast and Midwest

showed off-peak price increases of 20 

percent or more. PJM West showed a

striking difference between on and offpeak power price increases—5.4 percent

on peak and 24.9 percent off peak. This

dichotomy reflected the tendency of PJM

to have natural gas on the margin during

peak periods and coal in off-peak periods.

Entergy showed a similar pattern. 

Electric Power Markets National Overview

On-Peak Spot Prices Off-Peak Spot Prices

2003 2004 % Change 2003 2004 % Change

Northeast

Mass Hub $59.05 $61.47 4.1% $41.80 $42.94 2.7%

NY Zone G $61.73 $61.74 0.0% $42.12 $42.86 1.8%

NY Zone J $77.82 $76.63 -1.5% $48.70 $48.28 -0.9%

NY Zone A $51.36 $52.49 2.2% $35.78 $36.82 2.9%

PJM West $48.49 $51.10 5.4% $24.14 $30.15 24.9%

Southeast

VACAR $41.60 $48.27 16.0% $19.44 $25.23 29.8%

Southern $41.55 $48.67 17.1% $19.51 $26.01 33.3%

TVA $38.90 $44.23 13.7% $18.73 $22.14 18.2%

Florida $52.21 $58.31 11.7% $22.25 $29.02 30.4%

Entergy $41.47 $45.76 10.3% $18.39 $23.04 25.3%

Midwest

Cinergy $37.57 $43.31 15.3% $15.91 $19.88 24.9%

ECAR North $38.41 $45.58 18.7% $16.54 $21.00 26.9%

MAIN North $43.14 $47.94 11.1% $16.47 $20.28 23.2%

NI Hub $37.11 $42.03 13.2% $15.44 $17.57 13.8%

MAIN South $38.43 $42.85 11.5% $16.06 $18.41 14.6%

MAPP North $45.18 $47.06 4.2% $17.22 $19.12 11.0%

MAPP South $43.29 $45.90 6.0% $16.93 $19.00 12.3%

South Central

SPP North $41.66 $45.19 8.5% $18.48 $20.55 11.2%

ERCOT $46.49 $47.32 1.8% $30.51 $31.45 3.1%

Southwest

Four Corners $48.55 $50.51 4.0% $32.28 $35.45 9.8%

Palo Verde $49.10 $50.09 2.0% $32.84 $35.44 7.9%

Mead $50.65 $51.91 2.5% $33.75 $37.43 10.9%

Northwest

Mid- Columbia $40.73 $44.54 9.3% $34.04 $39.27 15.3%

COB $44.49 $49.09 10.3% $35.23 $40.58 15.2%

California

NP 15 $49.13 $54.46 10.9% $35.76 $41.35 15.6%

SP 15 $51.25 $55.20 7.7% $35.15 $39.26 11.7%

Table 5: Peak Spot Prices for Major Pricing Points ($/MWh)

Source: Derived from Platts and Dow Jones data. See Source Note 4.
State of the Markets Report • June 2005 59

Electric Power Markets National Overview

Overcapacity and Underinvestment

0

10

20

30

40

50

60

70

1960 1965 1970 1975 1980 1985 1990 1995 2000 2005

Capacity (GW)

Other

Oil

Nuclear

Coal

Renewable

Natural Gas - Other

Natural Gas - Gas Turbine

Natural Gas - Combined Cycle

Fig 5: Annual U.S. Capacity Additions 1960–2009

Source: Derived from Platts PowerDat data (February 2005).

During 2004, the generation sector of the

industry faced different circumstances:

• In aggregate across the country, the

industry had a significant degree of overcapacity as a result of the building boom

for combined cycle natural gas plants.

• Some specific load pockets had inadequate capacity (either in local generation

or in transmission capacity) and saw an

insufficient incentive to construct new

facilities to alleviate the problems.

In transmission, investment increased for

the fourth year in a row. Still, large-scale

transmission additions remained rare.

Generation Overcapacity

The United States built more generating capacity between

2000 and 2004 than in any earlier 5-year period (see Figure

5). Almost all of this capacity is combined cycle gas plants—

far more fuel-efficient than earlier gas plants. Independent

generating companies built most of this capacity—traditional utilities built less than a quarter of it. Most regions now

have a surplus of generation (see Table 6). 

The surplus of generation has reduced the profitability for

many combined cycle plants because:

• They do not run as expected. Investment studies typically were excessively optimistic in the

predicted hours of dispatch. In reality, new

plants have fewer opportunities to earn money.

Many combined cycle plants now run as intermediate, not baseload plants. As a result, system

operators call on them to cycle on and off more

than originally expected, which adds to maintenance costs. In some cases, too, the plants cannot get transmission service.

• They make less money than expected when they do run.

They tend to compete against other combined cycle plants

most of the time, not against less efficient, older gas-fired

plants. This competition reduces spark spreads (the difference between what natural gas costs and what the power

it generates sells for) so that each plant typically makes less

money than expected when it does run.

Taken together, these factors help explain why many independent generating companies face financial difficulties and

why many individual assets are financially distressed.

Summer Reserve Summer Reserve

Margin % Margin %

New England 30% SPP 20%*

New York 25% ERCOT 26%

PJM 36% Northwest 23%

Midwest 16% Southwest 29%

Southeast 32%* California 22%

* Reserve margins include uncommitted capacity not included in the regional market profiles. 

They also exclude all derates, which may overstate the available reserves in some regions.

Source: Derived from NERC 2004 ES&D and RTO/ISO data. 

Table 6: 2004 Reserve Margins
60 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Electric Power Markets National Overview

Underinvestment

Although the nation as a whole has access to more electric

power generation than it needs, some local areas suffer from

underinvestment. Price signals in those areas have not provided incentives for needed investments.

Table 7 shows the results of a net revenue test for each

region, with New York City broken out separately. The net

revenue tests shown here differ from those that a regional

entity might prepare in that we use price and cost estimates

from the same sources for all regions. 

A net revenue test: 

• Totals the market-related revenue streams a generator

could have received in 2004 (The estimates reported here

include spot market revenues for all hours when financially feasible to operate and capacity payments from RTO

capacity markets, when relevant, but not ancillary service

payments.); 

• Subtracts variable costs (fuel and variable operation and

maintenance); and 

• Compares the result to the target revenue needed to pay

for the fixed costs of a new plant. Estimating the revenues

needed to pay for fixed costs requires many assumptions,

and different analysts arrive at significantly different 

estimates. (The estimates reported here use EIA cost 

estimates, which tend to be lower than most.)

Making net revenue estimates consistently across the country inevitably leads to compromises that do not precisely

reflect individual regions. The results in the table would

change if the estimates used different assumptions for fixed

costs or if other revenue streams such as ancillary services

were used. In most cases, such changes do not affect the

overall results. The two major exceptions are:

• In New England, most of the revenue for a combustion

turbine (CT) would come from the forward reserve 

market that ISO-NE introduced in 2004—part of the 

revenue stream for ancillary services. ISO-NE estimates

that a CT could recover between 66 percent and 88 

percent of the revenues needed for investment.4

• EIA’s estimates of fixed costs are misleading for New York

City. EIA’s estimates are regional averages and fail to take

account of the unusually high costs of building power

plants in the most populated city in the country. The table

overstates the net revenue percentage for New York City

significantly. NYISO’s independent market advisor estimates that the cost recovery for a New York City combined cycle (CC) plant was marginal in 2004 and probably

would not have provided quite sufficient revenues.5 He

further estimated that a New York City CT would have

recovered just over half the needed costs. 

These results reflect the overall surplus of generation in the

country. Net revenues should be low in such circumstances,

reflecting the lack of need for investment. However, the

lack of market incentives is evident in most load pockets,

and there is little incentive to build new plants in places that

need them as well.

Table 7: Net Revenue

Region Point CC Net Revenue CT Net Revenue 

(as % of (as % of

Target Revenue) Target Revenue)

New England Mass Hub 59% NA

New York NYC (J) 285% 246%

Hud Val (G) 83% 27%

PJM West Hub 34% 9%

Midwest Cinergy 13% 0%

Southeast Southern 32% 0%

SPP SPP 32% 1%

ERCOT ERCOT 30% 0%

Northwest COB 48% 1%

Southwest Palo Verde 48% 2%

California SP-15 68% 3%

NP-15 58% 1%

Source: See regional overviews and “Analytic Note on Net Revenue Calculations”.
State of the Markets Report • June 2005 61

Electric Power Markets National Overview

Non RTO Regions. Utilities in regions that do not have

RTO markets usually fail to provide market signals for

investment inside load pockets. For example, New Orleans

is a load pocket, as are several cities within SPP. In the

absence of locational price signals in either Entergy or SPP,

price signals neither show the need for investment in a particular area nor promise to give the investor a return for

investing in the right place nor raise the cost of consumption. Investment in load pockets or in transmission lines to

avert congestion rely on traditional utility planning

approaches rather than market signals. 

In the West, rapidly growing Las Vegas has become a load

pocket. The relatively robust bilateral power market in the

West does not appear to provide enough locational detail to

justify investing in Las Vegas in particular. 

RTOs. Proponents of LMP often tout its ability to provide a

locational price signal for investment that would otherwise

be lacking. However, pricing in load pockets must deal with

two key issues at the same time—load pockets are subject

both to scarcity and market power, either of which can raise

prices. It has proven difficult in practice to allow the full

exercise of scarcity pricing while preventing any abuse of

market power. For this reason, RTOs use a variety of mechanisms to mitigate prices within load pockets that can sometimes blunt incentives for investment.

New England has two significant load pockets: Boston and

southwest Connecticut. Though both areas are short of generation, their average revenues were essentially the same as

for the rest of New England (except Maine, where generation is abundant). In southwest Connecticut, there is no

separate price zone for the load pocket. 

In both New England load pockets, ISO-NE frequently dispatched units that bid more than the prevailing market

price—“out-of-market” bids. Figure 6 illustrates this concept

where market prices remain lower and “uplift” side payments are collected outside the market and paid to certain

generators. Similarly, units called on for VAR and local support can receive a higher than market price. ISO-NE then

charges the additional payments to customers. In 2004, the

total amount of these out-of-market payments was $334 

million.

Many buyers see uplift payments as a way to force them to

pay prices that are above “market” value, that is, above the

published market-clearing price. However, from an investment perspective, such out-of-market payments remove

from the energy market the primary incentive to invest in

new generation or transmission. A net revenue analysis for

New England suggests that a new generator would have

received 59 percent of the revenues needed to justify having

invested in a combined cycle gas plant. That reflects the

market realities of New England outside the load pockets.

But given the lack of price differentiation between the load

pockets and other areas, it is also the price signal for the load

pockets.

In response to these problems in ISO-NE proposed a locational capacity market. This would provide revenues to

plants in load pockets and could give an incentive for localized new investment. ISO-NE and some local authorities

are also working hard to build a new transmission line into

southwest Connecticut. The fact remains that in 2004, there

were virtually no energy market signals to show the need for

such investment.

New York City is the one major load pocket in which a net

revenue analysis indicates that revenues from a combined

cycle plant might have justified the investment in 2004. In

Uplift

Demand

ISO Market 

Clearing 

Price

Price Absent 

Mitigations

Quantity

Price

Supply

Out-of-Market Bids

Fig 6: Out-of-Market Bids
62 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

fact, some market players are building new capacity in New

York City. However, even there the investment response

has not come easily. Between 2001 and 2005, NYPA, a state

agency, has built or is building the majority of the in-city

generation. A merchant transmission proposal to deliver

power from upstate into the city (the Conjunction project)

failed during the year.

Southern California could become a load pocket under

certain conditions. Recent concerns about possible shortages if summer is hot there in 2005. During 2004, the net

revenue test showed a southern California generator

receiving 68 percent of the revenues needed to justify

investment in a new combined cycle plant, higher than

any other region except New York. The price differential

between the desert Southwest and southern California

also increased. These are both market signals consistent

with a growing need for new capacity, but they do not

appear to be strong enough to justify building a new plant.

Given potential problems in southern California in the

summer of 2005, the question is whether electric power

price signals for new investment will provide enough lead

time to build new plants or transmission before shortages

occur. 

Transmission Investment

Electric transmission owners have increased their investments in transmission every year since 2000 (see Table 8).

Net plant additions in transmission, as reported in the

2004 FERC Form 1, were $3.828 billion—4.7 percent of the

total transmission plant in service. Transmission investment grew 69 percent between 2000 and 2004. 

These reported investments include all plant and equipment

associated with transmission, not just transmission lines.

Large transmission lines remain difficult to site and to build.

In 2004, a total of 931 circuit miles of new transmission lines

above 230 kilovolts came into service in the United States, a

0.6 percent increase to the transmission system already in

service (more than 150,000 circuit miles over 230 kilovolts).6

Electric Power Markets National Overview

During 2004, financial institutions and private equity entities became more important players in electric power markets in three ways. They:

• Acquired individual assets, at both the corporate and the 

plant level,

• Helped facilitate rapidly expanding trading in key power

markets, and

• Helped improve systems for doing business in the power

industry by, for example, addressing credit risk and clearing.

Asset Acquisition

Financial institutions acquired significant holdings in the

electric power industry in 2004. At the corporate level,

Goldman Sachs acquired Cogentrix, Credit Suisse First

Boston (CSFB) acquired United American Energy (UAE)

and AIG-Highstar Capital acquired 50 percent of

Duke/UAE American Ref-Fuel. Most of the electric power

holdings aquired by financial institutions and private equity

in 2004, however, were at the facility level. 

During 2004, almost 36 GW of generation assets changed

hands, a four-fold increase from 2003. Table 9 provides

details by buyer type. Effectively 5.8 percent of total capacity

in the industry changed hands.

Who acquired the assets? Investors within the electric industry doubled their acquisitions in 2004, but financial players

increased their acquisitions nearly six-fold, despite the fact

that investment banks virtually stopped buying power assets.

The new acquirers were private equity and hedge funds (23.2

GW) and lenders to assets that defaulted or were in danger of

Year Gross Transmission Transmission Net Transmission 

Additions Retirements Additions

2000 $2.6 $0.4 $2.3

2001 $3.4 $1.1 $2.3

2002 $3.3 $0.4 $2.9

2003 $4.0 $0.4 $3.5

2004 $4.3 $0.4 $3.8

Source: Derived from FERC Form 1 data including accounts 352, 353-359.1. See source note 5.

Table 8: Transmission Investment by Companies ($Billions)

Growing Role of Financial Institutions and Private Equity
State of the Markets Report • June 2005 63

Electric Power Markets National Overview

default (6.0 GW). Private equity itself accounted for 65 

percent of all the capacity that changed hands in 2004, 3.7

percent of all generation capacity in the United States. The

rise of private equity and hedge funds represents a change

from 2003, when investment banks accounted for most of

the asset acquisition at the plant level.

Increased Trading of Financial Products

During 2004, financial trading on the

IntercontinentalExchange (ICE) increased by a factor of 10.

Figure 7 shows nationally the volume of power traded 

financially for a given month, looking at contracts for a

month or longer. For example, the December volume

includes all trades made for the month of December or for a

strip of months which included December during all earlier

periods prior to the month. 

Trading in ICE financial swaps7 designed for market participants to trade future power quantities financially increased

in many regions around the country. This change was most

pronounced in PJM, where its products accounted for over 50

GWh per month in forward contracting. Most regions also

saw large percentage increases in the volume of ICE trading

during the year. The increase became especially pronounced

starting in September for most regions. Western New York

(Zone A) was an exception, having been fairly high throughout the year. 

2003 2004

Electric Industry Buyers

Utilities 0.7 1.6

Affiliated Power Producers 0.5 2.1

Public Sector (Munis and Coops) 1.1 0.4

Independent Power Producers 0.7 2.2

Total Electric Industry Buyers 2.9 6.3

Financial Buyers (Acquirers)

Private Equity and Hedge Funds 0.8 23.2

Lenders 0 6.0

Investment Banks 4.4 0.2

Total Financial Buyers 5.2 29.4

Total Acquired 8.1 35.7

Source: Derived from EIA data, confirmed with Platts PowerDat software.

Table 9: Asset Acquisition by Company Type (GW)

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

GWh

PJM NYISO A

NEPOOL Cinergy

SP15 NYISO G

NYISO J Palo Verde

MidC NP15

Fig 7: Financial Trading on ICE

Source: Derived from ICE on-peak financial swaps volumes. ICE products evaluated include monthly, dual monthly, quarterly, and calendar year contracts traded for 2004.
64 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Electric Power Markets National Overview

The increase in ICE swaps volumes follows ICE’s introduction of a clearing service8 in late 2003 for several hubs (PJM,

NYISO, Cinergy, SP-15, Palo Verde) and again in the summer of 2004 for others (ISO-NE, NP-15, Mid-C).

Participants may have moved some pre-existing business to

ICE to take advantage of the clearing service. The number

of financial transactions on ICE may have increased for

other reasons as well. ICE trends provide the best indication

available for changes in trading volumes in electricity, as

information on over-the-counter trading is lacking.

Financial trading in the electric industry appears to be one

part of a web of energy markets that link physical and financial markets for both fuel and power. The best indications

available are that financial trading in electric power is a more

important part of that web of energy markets than it was a

year ago. Financial instruments are more attractive in many

circumstances—the delivery obligation in physical deals can

be both cumbersome and costly. The increase in trading also

suggests an increasing ability for market participants to arbitrage between physical and financial markets for reasons of

cost, convenience or regulatory regime. 

Improvements in Credit and Clearing

Industry events during 2000 and 2001—from the

California “meltdown” to the PG&E and Enron bankruptcies to financial distress among most energy merchants—

heightened awareness of credit issues. Credit concerns, in

turn, lowered market liquidity. 

Market liquidity is, among other things, a function of the

availability of capital and (inversely) the credit capital

required to transact business. From 2000 through 2003, market liquidity declined and credit capital requirements

increased as market participants made the costs of credit

more explicit for their counterparties. They became more

diligent at assessing credit quality, set tighter credit limits

and collateral requirements, and revised credit requirements

more frequently. At the same time, energy merchants had

less capital available for energy transactions. 

In 2004, liquidity improved as surviving energy merchants

continued recovering, producers and some utility affiliates

became more active, and financial players joined longestablished investment banks Goldman Sachs and Morgan

Stanley in building energy trading capabilities. Overall,

these changes increased capital available to market participants. Increased capital improved the industry’s ability to

address credit issues, increased the ability of companies to

buy and sell energy, and increased market liquidity.

At the same time, market participants sought to reduce credit exposure by netting, clearing, and more efficient settlement. Clearing platforms including Nymex ClearPort,9 ICE

with the London Clearinghouse (LCH),10 and EnergyClear11

developed. More recently, more specialized approaches have

grown up to address more specific issues. For example,

North American Energy Credit and Clearing (NECC)12

entered physical clearing and Virtual Markets Assistance

Corp. (VMAC)13 netted insurance coverage.14 These activities are helping to reduce required credit capital.

FERC has addressed credit issues. It organized a joint credit

and clearing conference with Commodities Futures Trading

Commission (CFTC) in early 200315 and issued a notice of

proposed rulemaking for pipeline creditworthiness16 and

received comments later in 2003. FERC issued an electric

credit policy statement17 in late 2004 for transmission

providers and RTO/ISOs. The policy statement requires

greater transparency for all and calls for RTO/ISOs to accelerate settlements and develop other means to reduce mutualized credit risk among their market participants. These

efforts also facilitate the reduction of required credit capital.

Together, increased capital availability and reduced

required credit capital improved market liquidity in 2004.

The linkage of credit and market liquidity is important to

the Commission because liquid markets are a strong indicator of the competition that the Commission relies on to

provide just and reasonable rates.
State of the Markets Report • June 2005 65

Electric Power Markets National Overview

Conclusion and Remaining Questions

Electric power markets faced less stress in 2004 due to generally benign weather. They responded successfully in the few

cases of difficult weather conditions—in New England in

January and more broadly in the Northeast in December.

RTOs developed significantly during the year:

• MISO prepared for starting its markets in 2005.

• SPP became an RTO and prepared for a balancing market

in 2006.

• ISO-NE received approval for RTO status.

Overall, areas accounting for over two-thirds of the national

economy have opted for RTOs. At the same time, the

Southeast and the West outside California showed little sign

of moving toward RTOs in the near future.

Longer-term markets continued to show signs of being

prone to boom-bust cycles. During 2004, generating companies finished the last major group of combined cycle natural

gas plants started during the last boom. Most of the country

was in the bust part of the cycle with a glut of generating

capacity and financial distress for many companies. At the

same time, most load pockets with supply shortages did not

see market price signals that would justify new investment. 

The major questions facing electric power markets in the

future include:

• How well will short-term markets perform when faced

with more severe, more widespread, or more prolonged

weather incidents? Both winters and summers have

been mild for the last 2 years, so the markets have not

faced a major test recently.

• How will RTO markets adapt to regions that have a 

history of many separate control areas, such as MISO?

• Can markets signal the need to build capacity (generation, transmission, or price responsive demand) long

enough in advance to prevent shortages that lead to price

explosions or blackouts? The capacity markets of the

Northeast are one major effort to address this issue. Other

possible approaches include letting energy prices rise to

clear the market and traditional utility planning. Much of

the country has no obvious market mechanism to signal

the need for new building in advance of shortages. The success of capacity markets in addressing the issue is not yet

proven.

• Can electric markets institutions foster the development of more price responsive demand? With little

price response from demand, markets are more subject to

price spikes (in response to short-term shortages), to overbuilding (to avoid price spikes), and to greater cost (since a

large fraction of total investment is designed to meet peak

demand). Developing more price-responsive demand

raises a host of institutional issues including the difficulties of reconciling the jurisdiction of states over retail markets and federal jurisdiction over the purchasing as well as

selling side of wholesale markets.

• How will the industry integrate market institutions and

reliability requirements? Well-designed markets should

reinforce reliability, and reliability should support 

markets.
66 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Electric Power Markets National Overview

The individual regional profiles cover 10 regions: New

England, New York, PJM, the Midwest (MISO & MAPP),

the Southeast, SPP, ERCOT, the Southwest, the Northwest,

and California.

Each profile stands alone as a summary of the region’s electric markets in 2004. The profiles are designed to be as standard as possible but differ somewhat because of differences

in the information available from each region. RTO regions,

for example, have much more information available than

others. The profiles generally include the following sections:

Summary. The opening section of each profile includes:

• A brief description of the region and important factors

that affect its electric market.

• A map with average on-peak prices for 2004 for available

pricing points.

• A summary price table that includes annual on-peak

prices for the region for 2003, 2004 and a 5-year average. It

also provides price estimates from different sources,

where available, so the reader can compare, for example,

the RTO’s price with those provided by the trade press

(such as Platts) or an electronic exchange (such as ICE).

• Overall statistics for supply and demand, including estimates of reserve margins.

Major Focal Points for 2004. This section summarizes the

most important developments that affected the regional

market during 2004.

Spot Market Prices and Volumes. This section includes a

graph of key daily regional prices during the year. In many

cases it will include more than one price series so that the

reader can compare different data sources or different pricing points. It is especially useful for identifying price spikes

and seeing the overall range and volatility of prices through

the year. Where relevant, this section includes a second

pricing chart. In some cases, the second chart shows a second pricing point in more detail (as in southern and northern California). In others, it shows the difference between

day ahead and spot prices during the year. The text describes

key events that affected prices—for example heavy loads that

drove prices higher.

Financial Prices and Volumes. This section contains two

graphs:

• A plot of the forward price curve at several times during

2004. This graph shows how market expectations of

future prices changed during the year.

• A graph of the quantity of power for the region that traded under forward contracts on ICE during the year. This

indicates the change in the amount of financial trading

and shows striking increases in some regions.

Capacity Auctions. This section applies to those regions

that have RTO capacity markets (New England, New York,

and PJM). It includes a brief description of the market, a

graph of prices through 2004, and a graph of quantities 

traded in the auctions.

Resource Mix. This section shows the mix of generation in

the region (by fuel and generator type)—both by capacity

installed and by amount of power generated in 2003.

Market Concentration. This section shows the top 10 generating companies in each region (by capacity and total

power generated) in 2003.

Net Revenues. This section provides an estimate of how

much revenue a marginal plant could have generated from

energy and capacity markets during 2004 and compares the

result with an estimate of how much revenue it would take

to justify constructing the plant. It supplies estimates for

both a combustion turbine (for peaking) and a combined

cycle plant (for base and intermediate load). These estimates reflect the signal to investors as to whether it would be

(or would have been) worthwhile to make investments in

the region. Market signals should lead to higher net revenue

estimates in regions that are short of power and lower estimates where there is a surplus.

Regional Exports and Imports. This section shows a daily

Guide to the Regional Profiles
State of the Markets Report • June 2005 67

Electric Power Markets National Overview

graph of overall net imports for 2004. It also shows average

and maximum flows over major interfaces with other

regions.

Generation and Transmission Additions and Retirements.

This section shows changes to the physical infrastructure

over the last 3 years.

Short Articles. Each regional profile includes at least one

brief discussion that highlights an important event or development during the year in greater detail than is possible in

the standard sections.

1 Data collected from 2004 NERC ES&D database.

2 FERC/OMOI analysis of Bureau of Economic Analysis, Regional

Economic Accounts (Revised as of 12-15-04), and EIA 2003 Forms

906 and 861 data.

3 US Coal Supply and Demand: 2004 Review by Fred Freme; US Energy

Information Administration, April 2005.

4 ISO New England State of the Market Report 2004. May 4, 2005, 28-9.

5 2004 State of the Market Report—New York Electricity Markets. May

4, 2005, 6, presentation discussion.

6 Transmission data derived from NERC ES&D Data Base 2004,

updates from NERC as of 4/19/05, ERCOT data, and FERC research.

7 A fixed for floating financial swap exchanges dollar obligations and

liability based on a firm established price, which is liquidated against

a price that is based upon an index, but physical commitment is

never established.

8 Clearing is the mechanism used to erase the risk of principal-to-principal transactions (trading) through a transfer to an anonymous pool.

Clearing typically involves futures commission merchants, regulated

exchanges, membership liability, insurance products, margin, and

settlements to ensure the financial security of the transactions to all

the markets participants.

9 New York Mercantile Exchange (Nymex) began clearing over-thecounter energy transactions in 2002 and formed the Clearport platform for clearing and execution for a growing list of gas and power

products. Nymex Clearport volumes were 6,040,165 contracts in

2003 and 14,455,848 in 2004.

10 IntercontinentalExchange (ICE) is an online trading platform 

(electronic broker), which began clearing through the London

Clearing House (LCH) in 2002. Cleared volumes were 4,529,781 contracts in 2003 and 17,965,076 contracts in 2004.

11 EnergyClear was a membership clearing model where each participant had to be a member and contribute to a pool of guaranty funds

to protect against the default of a member. This model is different

from that of Nymex ClearPort and ICE/LCH where the protection is

mutualized among the Clearing Members (or Futures Commission

Merchants—FCM) and each participant must clear through an FCM.

EnergyClear started with five members and shut down in early 2004

after growing beyond the initial membership over the 2-year start up

effort.

12 North-American Energy Clearing Corporation (NECC) is gearing up to

start clearing of physical transactions on ICE in the summer of 2005,

beginning with power products from the ERCOT market and Henry

Hub gas.

13 VMAC (previously Virtual Markets Assurance Corporation) utilizes an

insurance model to provide multi-lateral netting—the primary focus

of clearing to reduce credit risk. VMAC anticipates start up during

the summer of 2005.

14 Commodity Futures Modernization Act (CFMA), enacted December

14, 2004, reauthorizes the Commodity Futures Trading Commission

(CFTC) and contains provisions for the regulation of designated clearing organizations (DCOs) for over-the-counter products by complying

with a set of core principles.

15 Joint FERC and CFTC conference on “Credit Issues in the Energy markets; Clearing and Other Solutions,” held February 5, 2003.

16 Docket No. RM04-4-000, “Creditworthiness Standards for Interstate

Natural Gas Pipelines” Notice of Proposed Rulemaking (NOPR)

issued February 12, 2004. FERC received comments. A decision is

pending.

17 Docket No. PL05-3-000, “Policy Statement on Credit-Related Issues

for Electric OATT Transmission Providers, Independent System

Operators and Regional Transmission Organizations” issued

November 19, 2004.

Endnotes
Source notes

1. Demonstrated capacity data are from Platts PowerDat, RDI

Modeled production Costs data set for calendar year 2003,

reflecting self-reporting from all utility and non-utility electric

power generating facilities with nameplate capacity of 50 MW

or more.

2. On-peak days for western nodes (NP-15, SP-15, Mid-Columbia,

COB, Mead, Palo Verde, and Four Corners) are defined as

Monday through Saturday excluding NERC holidays. On-peak

days for all other nodes are defined as Monday through Friday

excluding NERC holidays. Some regional prices will differ from

the almanac prices as other data sources were utilized at the

regional level.

3. FERC/OMOI analysis of 2004 ISO day-ahead on-peak LMPs from

http://www.iso-ne.com/smd/operations_reports/hourly.php.

Platts Megawatt Daily 2004 on-peak index prices are for the

Massachusetts Hub. ICE 2004 on-peak index prices are for the

Nepool Mass Hub. On-peak hours are 7am to 11pm. On-peak

days are Monday through Friday excluding NERC holidays.

4. The price increases reported here are for individual pricing

points in Platts, with the exception of Mead on-and off-peak

Dow Jones firm on-peak prices and NYISO off-peak ISO prices

(off-peak hours are all weekend and NERC holiday hours as well

as weekday hours 11pm to 7am). In particular, the PJM West

pricing point reflects activity at only that point, not for the

whole of PJM. Looking just at this point avoids the problem

that PJM grew during the year, so that average prices for the

whole of PJM represent different areas at different times during

the year.

5. FERC Form 1 data for 2004 is a preliminary data set based on

198 of 221 companies. The missing 23 companies accounted

for 6.7 percent of the Year Balance dollars in 2003. It was

assumed that their share of the total would remain constant in

2004. Transmiss-ion addition levels for the 198 respondents,

representing 93.3 percent of the whole ($3.99 billion) multiplied by (100/93.3) provides a preliminary 2004 transmission

addition level of $ 4.277 billion. 

Disclaimer: This report contains analyses, presentations, and 

conclusions that may be based on or derived from the data

sources cited, but do not necessarily reflect the positions or 

recommendations of the data providers. 

Electric Power Markets National Overview

68 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations
The California electric market comprises primarily the

California-Mexico Power Area (CAMX) subregion, as designated by the North American Electric Reliability Council

(NERC). Within CAMX an open-access, wholesale market is

managed by the California Independent System Operator

(CAISO), representing approximately 80% of demand within the

California electricity market. The portion of the CAMX power

area within Mexico consists of a small section along with transfer

capability limited to 800 MW total into California. CAISO manages more than 25,000 miles of transmission owned by Pacific Gas

& Electric Company (PG&E), Southern California Edison

Company, San Diego Gas & Electric Company, and participating

municipalities.1 The remaining 20% of California’s load is managed by municipal utilities and irrigation districts such as the Los

Angeles Department of Water and Power, the Sacramento

Municipal Utility District, and the Imperial Irrigation District. 

CAISO manages markets for imbalance energy, ancillary services,

and transmission usage. Wholesale energy and ancillary service

costs, including CAISO’s imbalance energy, totaled approximately $11.8 billion for 2004, compared with $10.8 billion for 2003.

Imbalance energy (the difference between scheduled energy and

actual load) represents less than 5% of energy consumed in

CAISO.2 Ancillary services (A/S) allow for generation to be held

in reserve to provide a margin of supply above the demand

requirement. CAISO provides access to, and allocates the capacity

of, California’s transmission to market participants. During the year CAISO experienced 4% demand growth with less

than comparable growth in generation. 

State of the Markets Report • June 2005 69

NP-15

ZP-26

SP-15

Zones

OR

AZ

CA

NP-15 NV

$39.61

SP-15

$44.72

 ZP-26 $39.25 

• High-level goals for resource

procurement were issued in

January when the California

Public Utility Commission

(CPUC) set in motion policy for

long-term procurement rules for

load-serving entities.

Stakeholders sought more definition, and the CPUC opened a

new omnibus proceeding on

electric utility resource planning. Workshops on implementation are forthcoming in 2005.3

• Insufficient new generation is

coming on line either to meet

demand growth or to compensate for generation retirements,

the California Energy

Commission (CEC) reported.

The CEC expected California to

have adequate supplies

through 2009, but has since

qualified that expectation, stating that, under hot weather

conditions or with significant

retirements of aging power

plants, the state’s reserve margins could become “dangerously thin, primarily in southern

California.”4

• A new power plant received

conditional approval of a power

purchase agreement between

Southern California Edison

(SCE) and a subsidiary it created to complete and operate the

partially constructed power

plant, Mountainview, located in

Redlands, Calif. The CPUC

granted conditional approval of

the project to address generation supply needed for southern

California. State agencies and

SCE had expressed concern

that as early as 2006 there

could be insufficient new generation to meet demand growth,

if new plants were not built.5

Focal Points for 2004

Supply Demand Statistics

2003 2004 Exp. 2005

Summer Generating Capacity MW 56,766 55,726 54,421

Summer Peak Demand MW 42,689 45,597 46,668

Summer Reserves MW 14,077 10,129 7,753

Summer Reserve Margin 33% 22% 17%

Annual Net Generation Gwh 180,740 184,168 NA

Annual Load GWh 231,241 239,769 NA

Annual Net Exports/Imports Gwh (51,110) (56,581) NA

SP-15 Zone Prices

2003 2004 5-Year

ISO (Incremental only) $39.89 $44.72 $57.60 

Platts $51.25 $55.20 $72.04

Dow Jones $51.17 $55.17 NA

Source: Derived from CAISO data. See source note 3.

Source: Derived from CAISO data. See source note 1.

2004 Average Zonal Prices for On-peak Hours ($ per MWh)

NP-15 Zone Prices

2003 2004 5-Year

ISO (Incremental only) $37.08 $39.61 $61.35 

Platts $49.13 $54.46 $75.12 

Dow Jones $49.08 $54.47 NA

Source: Derived from CAISO, Dow Jones and Platts data. See source note 2.

California (CAISO) Electric Market Profile
70 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Day-ahead, peak bilateral prices from Platts,

IntercontinentalExchange (ICE), and Dow Jones are illustrated, as well as CAISO real-time prices. Prices in 2004 were affected by the following: implementation of Phase 1B; nuclear unit

outages; a major transmission line failure near Palo Verde that

tripped over 4,000 MW of generation throughout the West and

pushed imbalance energy prices in SP-15 to more than $116;

and derating of the Pacific DC Intertie (PDCI) for repairs and

upgrades through the summer and fall. 

Implementation of a new Real-Time Market Application on

October 1 contributed to an increase in real-time price volatility and price spikes. The real-time price volatility declined later

in the year as CAISO adjusted software parameters and generation and transmission resources returned to service.

Ancillary Services saw significant price spikes for spin, nonspin, and regulation services throughout the year. Offers to sell

A/S were often less than the capacity requirement for reserves.

Typically, less supply is available during “shoulder periods”

(seasonal off-peak periods) when generators and transmission

lines are taken out of service for repairs. In 2004, capacity was

further reduced after the loss of a Diablo Canyon nuclear unit,

a San Onofre nuclear unit, and some capacity on the Pacific DC

Intertie. The lack of generation resources led to unusual price

spikes for reserves, such as A/S for lower quality resources

exceeding prices for the higher quality resources. The daily

weighted average nonspin price exceeded $100 for at least one

day during each of the months from August to December. 

In 2004, the daily peak load hours averaged 30,275 MW. Dayahead forecasted loads for the California ISO generally tracked

real-time volumes, but the two diverged by as much as 12% on

a few occasions. In NP-15 bilateral trading, Platts-reported volumes averaged 1,470 MW and peaked on November 26 and 27

at 2,975 MW; ICE volumes averaged 16,852 MW and peaked on

July 9 and 10 at 50,400 MW. In SP-15 bilateral trading, ICE volumes averaged 26,072 MW and peaked on October 29 and 30 at

88,800 MW; Platts-reported volumes averaged 2,459 MW and

peaked on September 1 and 2 at 5,800 MW.

California (CAISO) Electric Market Profile

SPOT MARKETS: PRICES AND VOLUMES

Daily Average of Southern California On-Peak Prices

$0

$20

$40

$60

$80

$100

$120

$140

Jan

FebMar

Apr

May

Jun

Jul

AugSep

Oct

NovDec

$/MWh

Platts SP-15 ICE SP-15

ISO SP-15 Dow Jones SP-15

Daily Average of Northern California On-Peak Prices

$0

$20

$40

$60

$80

$100

$120

$140

Jan

FebMar

Apr

May

Jun

Jul

AugSep

Oct

NovDec

$/MWh

Platts NP-15 ICE NP-15

ISO NP-15 Dow Jones NP-15

Source: Derived from CAISO, Dow Jones, Platts and IntercontinentalExchange (ICE)

data. See source note 4.

Source: Derived from CAISO, Dow Jones, Platts and ICE data. See source note 4.
For California, financial markets consist of both physical forwards and financial swaps. Market participants use many platforms for their financial transactions. Data are available only for

ICE and the New York Mercantile Exchange (Nymex). ICE began

clearing SP-15 in December 2003 and NP-15 in August 2004.

Nymex ClearPort began trading NP-15 and SP-15 financial swaps

in June for July and future months. 

Trading of ICE NP-15 and SP-15 monthly physical products for

2004 was highest in the third and fourth quarters. Trading for the

fourth quarter was twice first-quarter volumes for NP-15 and 20%

higher for SP-15. SP-15 volume was higher than NP-15 trading on

both ICE and Nymex ClearPort for both physical and financial

products.

Financial trading of SP-15 on ICE overtook physical trading in the

second quarter and by December was more than double physical

volume. On ICE, financial trading increased 21-fold for SP-15

over the course of trading for 2004; NP-15 trading increased more

than 61-fold, although the overall volumes for NP-15 were 10% of

SP-15. From August, trading of NP-15 on Nymex ClearPort outweighed trading on ICE.

The increase in trading of NP-15 and SP-15 financial products is

consistent with general trends in electricity trading as more nontraditional electricity trading entities (hedge funds and banks)

have become active in these financial markets, and as industry

credit has improved. Some of the increased trading on ICE might

be due to its starting to offer clearing of trades, as noted above.

State of the Markets Report • June 2005 71

FINANCIAL MARKETS: PRICES AND VOLUMES

California (CAISO) Electric Market Profile

SP15 Swaps Prices from Trade Date SP-15 Forward and Swaps Volume

$0

$20

$40

$60

$80

$100

$120

$140

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

$/MWh

12/15/2003

03/15/2004

06/15/2004

09/15/2004

0

500

1,000

1,500

2,000

2,500

3,000

Jan

FebMar

Apr

May

Jun

Jul

AugSep

Oct

Nov

Dec

MWh (thousands)

ICE SP-15 Forward Volume ICE SP-15 Swaps Volume

ClearPort SP-15 Swaps Volume

Source: Derived from ICE data. See source note 5. Source: Derived from ICE and Nymex data. See source note 5.

Source: FERC/OMOI analysis of Platts data. See source note 7.

CAISO Continued to Experience Congestion Challenges

Congestion costs occur when transmission facilities are constrained and cannot carry more power. At those times the system must use higher cost generators located close to load,

rather than lower cost generators elsewhere. CAISO estimates

that congestion costs in 2004 were $482 million, up from $177

million in 2003. Intra-zonal congestion was $426 million.

In California, suppliers may schedule power transfers without

regard to transmission constraints—for example, the constraint at the Miguel substation regarding energy transmission

into San Diego—but the scheduled power may be physically

undeliverable. This practice increases congestion costs. The

long-term “seller’s choice” contracts entered into by the state

in 2001 account for much of this. Congestion was also

increased by the seven-week San Onofre refueling outage

(approximately $9 million in congestion costs) and intermittent outages of the Sylmar substation during the summer

(approximately $22 million). 

CAISO uses Reliability Must Run (RMR) contracts for certain

generating units in load pockets to meet local reliability needs

(e.g., voltage support and contingency reserves) and to mitigate local market power (see Offer Mitigation box, p. 74). RMR

units may also be dispatched in real time in response to intrazonal congestion. When the RMR units were dispatched for

this purpose, CAISO calculated the net real-time costs (variable

costs in excess of reliability costs) for intra-zonal congestion as

$49 million in 2004, up from $27 million in 2003.6
72 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

California (CAISO) Electric Market Profile

Capacity and Generation by Fuel and Prime Mover

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Capacity Net Generation 

Share of Regional Total (%)

OIL CT

GAS/OIL CT

GAS CT

OIL ST

GAS/OIL ST

GAS/OIL CC

GAS ST

GAS CC

COAL ST

NUCLEAR

RENEWABLES

HYDRO

Source: Derived from Platts data. See source note 6.

In 2003, hydroelectricity, wind, nuclear energy, and coal constituted 43% of total California capacity and provided 59% of net

generation. The region depends heavily on gas-fired capacity

providing 45% of the capacity in 2003 and contributing 30% of

annual net generation. 

2003 RESOURCE MIX

2003 MARKET CONCENTRATION

The top 10 owners provided 59% of capacity and 55% of generation in California in 2003. Seven of the top 10 generation owners

in CAISO were independent power producers or utility affiliates,

who built or acquired generating assets outside of their traditional service territories. The major investor-owned utilities in

California have divested substantial portions of their generating

assets or transferred them to unregulated affiliates.

The residual supplier index (RSI) is one measure of the extent to

which a single generation supplier is pivotal in the real-time energy market on an hourly basis. CAISO’s Department of Market

Analysis (DMA) calculated that the RSI for 2004 decreased from

2003 levels, but was still significantly above the 1.0 RSI Index level

for all hours in the year. The RSI dropped below the 1.1 level for

22 hours in the year. This indicates competitive conditions in the

ISO control area and less potential for market power.7 

Capacity for thermal units, and in particular natural gas-fired

units, changed the most in 2004. More than 97% of the new generation that came on line in 2004 was fueled by natural gas. The

CAISO initiated the return of the two Reliant Etiwanda thermal

units in mid-2004, accounting for 640 MW of the 750 MW of generation additions. These units were brought back into service

under RMR contracts that preclude them from setting market

prices. 

Capacity and Generation of Top 10 Companies

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Capacity Net Generation

Share of Regions Total (%)

Intermountain Power

Agency

Western Area Power

Administration

Mirant Corp.

Reliant Energy, Inc.

Calpine Corp.

Duke Energy Corp.

AES Corp., The

Edison International

Los Angeles Dept. of

Water & Power

PG&E Corp

Source: Derived from Platts data. See source note 6.
State of the Markets Report • June 2005 73

REGIONAL EXPORTS AND IMPORTS

CAISO was a net importer of energy, importing an annual average of 6,587 MW. The highest daily net imports were on

December 9, averaging 9,041 MW, whereas the lowest daily net

imports were on February 29, averaging 3,448 MW. The highest

hourly net imports were for hour 15 on September 7 for 11,024

MW; the lowest hourly net imports were for hour 2 on March 1

for 2,197 MW.

Regionally, CAISO receives most of its power from the

Northwest and Arizona, and on average is a net exporter of energy to the Sacramento Municipal Utility District. Zonally, both

NP-15 and SP-15 were net importers from external control areas,

although, on January 1, NP-15 was a net exporter. On net, SP-15

imported more than three and a half times the amount that NP15 did.

Hourly Net Interchange

External Interface Max Max Avg 

Exports - MW Imports - MW Net Exports

(Imports) MW

Arizona 1,830 6754 (3765)

Imperial Valley 365 597 (331)

LADWP 1,176 1626 (135)

Mexico 270 515 (125)

Nevada/Utah 335 1196 (569)

Northwest 1900 5867 (2457)

SMUD 1973 430 795

Average Daily Net Interchange

-10,000

-9,000

-8,000

-7,000

-6,000

-5,000

-4,000

-3,000

-2,000

-1,000

0

Jan

FebMar

Apr

May

Jun

Jul

AugSep

Oct

NovDec

Net Exports (MWh)

NP-15

SP-15

Total

Source: Derived from CAISO data. See source note 7.

Source: Derived from CAISO data. See source note 7.

Average Hourly Zonal Exports

Zone Max Max Avg 

Exports - MW Imports- MW Net Exports

(Imports) MW

NP-15 2292 4595 (1383)

SP-15 3069 10280 (5203)

Source: Derived from CAISO data. See source note 7.

During 2004, CAISO set seven new records for energy

usage, reaching 45,597 MW on September 8. The previous

record of 43,609 MW was set in July 1999. Demand peaked

at levels not projected to be reached until 2006. This was a

tight year for operating reserves for the CAISO. In May,

California reached record temperatures, running about 10

degrees above the forecasts for southern California. A

record temperature on March 29, combined with 770 MW

of generation tripping, resulted in the ISO declaring a

Stage 1 Emergency. CAISO projected supply margins on

the thin side for the remainder of the summer in SP-15

and initiated the return to service of two mothballed

Etiwanda power plants located within the Los Angeles

Basin load pocket for a total capacity addition of 640 MW.

The two plants were designated as Reliability Must Run

(RMR) units, which allowed the ISO to use them to meet

local reliability needs. The timing was fortunate. The second unit came on-line the day before the CAISO experienced its record peak for SP-15 of 25,743 MW on

September 10. During this record peak load day, the ISO

grid operator depleted its entire operating reserves in SP15 and reach transfer capability limits on its transmission

into that area. The CAISO avoided blackouts, but

expressed concern about the deliverability of reserves to

SP-15. The rest of the West experienced high heat during

some of the same periods and had power still available to

export to California with the exception of varying

amounts of transmission congestion.8

California (CAISO) Electric Market Profile

CAISO Experiences Seven New Record Peak Load Days
74 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

California (CAISO) Electric Market Profile

Generation Additions. In the CAISO region, 10 generation

units came on line. The largest were two previously mothballed

320 MW units at Reliant’s Etiwanda plant, located in SP-15 to

serve load in the Los Angeles Basin. The Etiwanda units were

brought back into service under RMR contracts that preclude

them from setting market prices. Capacity additions in 2004

were lower than in the two previous years. Total capacity in

2004 increased by 748 MW of which the net additions of new

plants was approximately 110 MW, generation retirements

totaled 180 MW, and the Etiwanda reinstatement accounted for

640 MW.9

Transmission Additions. Three significant transmission projects were completed in CAISO: the Path 15 upgrade, the Miguel

substation upgrade, and the Pacific DC Intertie at Sylmar substation. 

The Path-15 upgrade is a new 84-mile, 500 kV transmission

line, providing an additional 1,500 MW of transfer capability

between the southern and the northern portions of the state.10

After the upgrade took effect on December 14, Path-15 energy

flows increased 40% in the south-to-north direction. 

San Diego Gas & Electric’s Miguel substation was upgraded to

allow an additional 100 MW to 400 MW of power into the San

Diego area. This substation effectively limited transmission

transfers from Arizona into southern California. San Diego Gas

and Electric estimated that the $30 million project would

reduce congestion costs by $18 million annually and would ease

access to more efficient generation from the Southwest. These

benfits should accrue once a second upgrade is completed in

2005. The upgrade took effect October 31.

The Pacific DC Intertie was upgraded between early summer

and year end. The addition of a transformer bank at the Sylmar

(Los Angeles) substation doubled its transfer capability from

800 to 1,600 MW, increasing capability between the Los

Angeles Department of Water and Power and CAISO.

Maintenance was performed at both ends of the line (Los

Angeles and the Pacific Northwest) to update equipment and

improve reliability. The line was down for short periods in early

summer, operated at reduced capacity throughout the summer,

was taken off-line again September 30, and was restored to full

2,200 MW capacity by December 30. 

Capacity Additions

-2000

-1000

0

1000

2000

3000

4000

5000

2002 2003 2004

MW

CAISO Additions

CAISO

Retirements

CAISO

Mothballed

GENERATION AND TRANSMISSION ADDITIONS AND RETIREMENTS

Source: Derived from CAISO, EIA and Platts data. See source note 8.

CAISO uses a Bid Cap and Automatic Mitigation

Procedures (AMP) to address economic withholding,

complementing its Must Offer requirement to address

physical withholding. The Bid Cap of $250/MWh is a

“soft” cap because sellers can submit bids above this

price, but the bids do not set the market clearing price

(and are subject to justification and refund). Therefore,

the market clearing price cannot exceed $250. 

AMP operates in CAISO’s real-time market. It mitigates

an energy offer if the offer violates an explicit threshold

(“conduct test”) and materially affects the market clearing

price (“impact test”). AMP takes effect only when prices

are expected to exceed $91.87. AMP operates system-wide

(System AMP) and also locally on offers from resources

that are taken out of merit order to alleviate intra-zonal

congestion (Local AMP). During 2004, System AMP mitigated no bids (i.e., no bids failed both the conduct and

impact tests). Local AMP mitigated fewer than 2% of the

out-of-merit dispatches, totaling $318,507.

Offer Mitigation
State of the Markets Report • June 2005 75

California (CAISO) Electric Market Profile

As shown, 2004 annual net revenues from energy for gas-fired

technologies were below the five-year average for the third consecutive year, in part, because of relatively large net revenues in

2000 and 2001. Annual net revenues from energy increased from

2003 for a combined cycle in NP-15 and SP-15 of 8.3 and 0.5 percent, respectively. In both NP15 and SP15, revenues from energy

for a combustion turbine declined to a five-year low. 

We estimate that new gas-fired combustion turbines in California

require $64.29/kW-yr, and gas-fired combined cycle plants require

about $87.85/kW-yr, to meet debt and equity requirements. 

In 2002, 2003, and 2004 estimated net revenues for gas-fired combined cycle and combustion turbine plants in California were

below these thresholds. (The five-year average net revenues

exceed these thresholds only because of exceptionally large revenues from high-priced periods in 2000 and 2001.) Energy markets alone did not signal the need for new investment in 2004.

0.00

50.00

100.00

150.00

200.00

250.00

300.00

350.00

400.00

2000 2001 2002 2003 2004

$ / kW-year

CC Net Revenue

CT Net Revenue

CC New Entry Costs

CT New Entry Costs

Northern California Net Revenue from Energy

Source: Derived from Platts day-ahead gas prices for PG&E Citygate and Socal Gas

Large Packages and Platts day-ahead power prices for NP15. See ”Analytical Note on

Net Revenue Calculations” in the Other Material section for details.

NET REVENUE

0.00

50.00

100.00

150.00

200.00

250.00

300.00

350.00

400.00

2000 2001 2002 2003 2004

$ / kW-year

CC Net Revenue

CT Net Revenue

CC New Entry Costs

CT New Entry Costs

Southern California Net Revenue from Energy

Source: Derived from Platts day-ahead gas prices for PG&E Citygate and Socal Gas

Large Packages and Platts day-ahead power prices for SP15. See ”Analytical Note on

Net Revenue Calculations” in the Other Material section for details.
76 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

California (CAISO) Electric Market Profile

1. Prices are CAISO on-peak balancing prices for the zones identified.

Peak hours are from 6:00 a.m. to 10:00 p.m. Monday through

Saturday excluding NERC holidays.

2. CAISO balancing, Platts Megawatt Daily and Dow Jones day-ahead

prices are firm on-peak for the SP-15 and NP-15 zones. CAISO data

are from http://oasis.caiso.com. CAISO prices include only that segment of the market reflected in the real-time balancing market,

which may lead to differences with published price indices.

3. Data are from CAISO Summer Assessments for 2003, 2004 and

2005. Reflects CAISO load only. Summer peak demand is instantaneous. Excludes the Los Angeles Department of Water and Power,

Sacramento Municipal Utility District and Imperial Irrigation District.

Generation capacity includes dynamically scheduled generation and

excludes all derates of resources and other imports.

4. CAISO balancing, Platts Megawatt Daily, IntercontinentalExchange

(ICE) and Dow Jones day-ahead prices are firm on-peak for the SP15 and NP-15 zones. CAISO data are from http://oasis.caiso.com.

5. ICE on-peak forward and swap prices and volumes are for SP-15 and

include monthly, dual monthly, quarterly, and calendar year contracts traded for 2004. New York Mercantile Exchange (Nymex)

ClearPort on-peak swaps volumes are for SP-15 and are traded by

month. 

6. Data from Platts PowerDat, RDI Modeled Production Costs dataset

for calendar year 2003 reflecting self-reporting from all utility and

nonutility electric power generating facilities with nameplate capacity of 50 MW or more.

7. Average net interchange based derived from CAISO real-time scheduled tie values from http://oasis.caiso.com.

8. Data from CAISO, Energy Information Administration (EIA) Form

860, Platts NewGen and Platts PowerDat. All generation is summer

capacity unless otherwise indicated.

Disclaimer: This report contains analyses, presentations and 

conclusions that may be based on or derived from the data sources

cited, but do not necessarily reflect the positions or recommendations

of the data providers. 

Source notes

1 The Participating Transmission Owners (PTOs) in the ISO Control

Area are PG&E, SCE, SDG&E, City of Vernon, City of Anaheim, City of

Azusa, City of Banning, and City of Riverside. All PTOs are also utility

distribution companies (UDC). Other UDCs are City of Pasadena and

Lassen Municipal Utility District. Metered Subsystem (MSS) customers in the ISO Control area are Northern California Power

Authority, The City of Roseville, and Silicon Valley Power. Other loadserving entities that the ISO provides services for include (but are

not limited to) Western Area Power Administration, California

Department of Water Resources, Metropolitan Water District of

Southern California, Modesto Irrigation District, Turlock Irrigation

District, and City of Redding.

2 Most energy within CAISO’s control area is generated by the utilities

and purchased under bilateral contracts with suppliers such as merchant wholesale generators and qualifying facilities. State-procured

“sellers choice” contracts (procured during the 2001 energy crisis)

covered 32% of the three, large investor-owned utilities’ peak energy requirements in 2004. 

3 California Public Utilities Commission, Decisions 04-01-050, 04-10-

035, and 04-12-048.

4 Integrated Energy Policy Report 2004 Update [100-04-006CM],

California Energy Commission, November 2004, vi.

5 FERC granted conditional approval of the Mountainview project,

subject to certain modifications such as accounting provisions and

pass-through of actual operating costs. FERC also ordered that it

would hold all future power purchase agreements to the Edgar standards. 106 FERC 61,183.

6 Source: CAISO. Total RMR costs for 2004 were $649 million, up from

$490 million in 2003. The amount attributable to intra-zonal congestion costs was $49 million in 2004, $27 million in 2003. RMR units

rose in 2004 by a net of 10. The RMR cost increase was attributable

mostly to higher natural gas prices and the need for congestion

management in southern California because of unexpected generation outages.

7 April 2004 Annual Report on Market Issues and Performance, the

California ISO Department of Market Analysis.

8 CEC and CAISO.

9 CAISO, Platts NEWGen as of March 1, 2005, EIA Form 860. All generation is in summer capacity unless otherwise indicated. Capacity

Additions and Retirements are for calendar year 2004, based on

Platts and EIA net summer capacity estimates and FERC staff

research. They may differ from the Summer Generating Capacity in

the Supply Demand Statistics table. Summer Generating Capacity

may be projected for the summer peak, may omit some calendar

year additions, and may reflect actual demonstrated capacity and

deratings.

10 Path-15 south-to-north transfer capability increased by 1,500 MW to

5,400 MW from 3,900 MW; the north-to-south transfer capability

increased by 1,100 MW to 3,300 MW from 2,200 MW.

Endnotes
The Midwest electric market includes the East Central Area

Reliability Coordination Agreement (ECAR), MidAmerica Interconnected Network (MAIN), and MidContinent Area Power Pool (MAPP) regions, excluding those

areas in PJM Interconnection LLC (PJM) at the end of 2004.

The Midwest independent Transmission system operator

(MISO), a regional transmission organization (RTO) since

2002, operates in all three regions. MISO did not administer an

energy market in 2004, but started operating one in 2005. In

2004, market participants traded bilaterally at several trading

points, including Cinergy Corp., Northern Illinois, and

Northern MAPP, based on prices reported in Platts or using

IntercontinentalExchange (ICE).1 Average 2004 prices for firm,

peak deliveries into Cinergy increased 15% in nominal dollars

from 2003. 

The region has ample reserves. Overall, 2005 summer reserve

margins are projected to be 23% and are expected to stay at or

near this level through 2009, with expected capacity additions

keeping pace with projected demand growth of around 2%

(North American Electric Reliability Council (NERC) 2004

Long-Term Reliability Assessment). Persistent transmission

constraints in Wisconsin and the Upper Peninsula of Michigan

(WUMS) have led to higher prices there than in other parts of

the region. Although transmission congestion occurs throughout the region, it is generally not sustained in other locations.

Midwest (MISO) Electric Market Profile

State of the Markets Report • June 2005 77

MAPP

MAIN

ECAR

NERC Regions

MI

NC

KS

MAIN - S

$42.85

ECAR - N

$45.58

MAPP - N

$47.06

MAPP - S

$45.90

MAIN - N

$47.94

CINERGY

$43.31

PA

SD

CO

WY

MT MN

NE

ND

IA

IL

WI

OH

KY

WV

VA

IN

MO

TN

• Transmission Loading Relief

(TLR). As a bilateral market in

2004, the Midwest managed

congestion in real time with

TLRs. Significant congestion

(TLR level 3 and higher) in

2004 totaled 10,208 hours and

10,736 hours in 2003. TLRs

were concentrated at the border with TVA, in Wisconsin and

the Upper Peninsula of

Michigan, and in Iowa. The

most significant event, an

emergency TLR Level 6,

occurred in northern Indiana 

in October, just after AEP

joined PJM. A rapid increase 

in flows from west to east

threatened to overload critical

transmission lines. 

• Deepening Drought. Missouri

River flows have been below

normal and dropping for the

last 4 years. At Fort Peck Dam

near the Missouri River headwaters, flows were at record

lows of 60% of the 30-year

average. Drought affects the

entire region, including

Canada, reducing hydropower

imported from Manitoba.

Resulting 2004 transmission

flows increased from south to

north, and prices were higher

in the north as a result. Low

water could lead to environmental restrictions on about

10,000 MW of generating

plants that use the river for

cooling.2

• Shifting Mix of Generation.

Ample supplies, big reserve

margins, and high natural gas

prices scuttled many natural

gas projects. Long-term 

plans are shifting to coal, 

with some coal plants under

construction and others

planned. Wind energy was 

the near-term technology of

choice, aided by renewal of 

the wind power tax credit and

state efforts toward renewable energy. Half of new U.S.

wind capacity in 2004 (204

MW) was built in the

Midwest.3

• Increases in Financial Trading.

The Cinergy Hub continued to

be very active in trading of

standard physical products

such as firm fixed contracts

with liquidated damages.

Financial products became

important, with new players

such as hedge funds entering

the electricity market and 

volumes increasing throughout the year. By year’s end,

trading of financial swaps on

ICE reached about one-third

the volume of physical 

trading, up from very small

volumes early in the year. 

Focal Points for 2004

Supply Demand Statistics

Projected Projected

2003 2004 2005

Summer Generating Capacity MW 155,929 158,211 159,369

Summer Peak Demand MW 134,066 136,284 129,789

Summer Reserves MW 21,863 21,927 29,580

Summer Reserve Margin 16% 16% 23%

Annual Net Generation GWh 705,696 715,823

Cinergy Hub Prices

2003 2004 5-Year

Platts $37.57 $43.31 $37.29

ICE $37.48 $43.25 NA 

Dow Jones $37.67 $43.39 $37.75

Source: Derived from Platts, ICE and Dow Jones data. See source note 2. Source: Derived from NERC and Platts data. See source note 3.

Source: Derived from Platts data. See source note 1. 

2004 Average Regional Prices for On-Peak Hours ($ per MWh)
For the Midwest, financial markets consist of both physical forwards and financial swaps. As illustrated in the volume graph,

physical trading outweighed financial trading at the Cinergy Hub

on ICE for 2004. However, the financial trading position

increased relative to physical trading over the year. For the first

quarter, ICE physical trading volumes were 30 times greater than

the financial trading volumes, whereas for the fourth quarter ICE

physical trading volumes were three times greater than the financial trading volumes. ICE financial trading increased 12-fold for

fourth quarter trading over first quarter trading, whereas physical

trading increased roughly 20% for the same period. 

The increase in trading of Cinergy financial products is consistent

with the trend in electricity trading as more nontraditional electricity trading entities, namely hedge funds and banks, have

become active in these financial markets and as industry credit

has improved.

78 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Day-ahead peak bilateral prices from Platts, ICE, and Dow Jones

are shown in the illustrations. Summer prices remained at moderate levels, consistent with generally mild summer weather.

Cinergy prices remained below $60, with only a few exceptions,

despite high gas prices. The most noticeable exception to these

moderate prices occurred in December, when the prices in northern MAPP were $20 above other prices and reached $85 during a

cold snap just before Christmas. 

In reports of bilateral trading at the Cinergy Hub, Platts volume

peaked on February 20 at 13,470 MW and averaged 4,327 MW;

ICE volume peaked on February 20 at 133,600 MW and averaged 53,647 MW. For bilateral trading at the ECAR North Hub,

Platts volume peaked on January 22 at 2,600 MW and averaged

943 MW.

Midwest (MISO) Electric Market Profile

SPOT MARKETS: PRICES AND VOLUMES

FINANCIAL MARKETS: PRICES AND VOLUMES

Daily Average of Various Midwest On-Peak Prices

$0

$20

$40

$60

$80

$100

$120

$140

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

$/MWh

Platts Cinergy Platts ECAR North

Platts MAIN North Platts MAIN South

Platts MAPP North Platts MAPP South

Daily Average of Various Cinergy Prices

$0

$20

$40

$60

$80

$100

$120

$140

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

$/MWh

Platts Cinergy

ICE Cinergy

Dow Jones Cinergy

Source: Derived from Platts data. See source note 1. Source: Derived from Platts, ICE, and Dow Jones data. See source note 2. 

Cinergy Swaps Prices from Trade Date Cinergy Forward and Swaps Volume

$0

$20

$40

$60

$80

$100

$120

$140

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

$/MWh

12/15/2003

03/15/2004

06/15/2004

09/15/2004

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

MWh (thousands)

ICE Forward Volume

ICE Swaps Volume

Source: Derived from ICE data. See source note 4. Source: Derived from ICE data. See source note 4.
State of the Markets Report • June 2005 79

Midwest (MISO) Electric Market Profile

Capacity and Generation by Fuel and Prime Mover

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Capacity Net Generation 

Share of Regional Total (%)

OIL CT

GAS/OIL CT

GAS CT

OIL ST

GAS/OIL ST

GAS/OIL CC

GAS ST

GAS CC

COAL ST

NUCLEAR

WIND

HYDRO

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Capacity Net Generation

Share of Regions Total (%)

Dynegy, Inc.

Wisconsin Energy Corp.

Cinergy Corp.

Xcel Energy, Inc.

Alliant Energy Corp.

CMS Energy Corp.

E.ON AG

FirstEnergy Corp.

DTE Energy Co.

Ameren Corp.

Source: Derived from Platts data. See source note 5.

Source: Derived from Platts data. See source note 5.

In 2003, hydroelectric power, wind, nuclear energy, and coal

totaled 74% of total Midwest capacity and provided 97% of net

generation. The region depends primarily on coal resources,

which made up almost two-thirds of total capacity and provided more than 80% of the annual generation in 2003, and

nuclear generators, which made up 7% of total capacity and

provided 12% of 2003 generation. 

2003 RESOURCE MIX

2003 MARKET CONCENTRATION

The top 10 owners provided 60% of capacity and 61% of generation in the Midwest in 2003. Many of the largest suppliers of

load in the Midwest were also the largest owners of generation

and able to cover much of their load through self–supply.

In 2004, capacity concentration was approximately the same as

in 2003.

Capacity and Generation of Top 10 Companies
80 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Midwest (MISO) Electric Market Profile

In 2004, 3,452 MW of generation was added in the Midwest,

and 935 MW of generation retired.4

Generation Additions. In the Midwest region, 10 generation projects came on line. The largest is the 1200 MW

Covert Plant near Lake Michigan, one of three new independent power producer (IPP) projects in the region. The

other IPPs are the 598 MW Riverside Energy Center and a

12-MW addition to an existing wind project. The capacity

additions in 2004 were greater than in 2003 but significantly

fewer than in 2002. During 2004, 935 MW of capacity

retired. The largest plant to retire was the 542 MW, natural

gas powered, Greater Des Moines Energy Center.5

Transmission Additions. No transmission projects (of 230

kV or higher) were completed during 2004 in the Midwest.6

Capacity Additions

(2,000)

-

2,000

4,000

6,000

8,000

10,000

2002 2003 2004

MW

Midwest Additions

Midwest Retirements

Midwest Mothballed

GENERATION AND TRANSMISSION ADDITIONS AND RETIREMENTS

Source: Derived from EIA and Platts data. See source note 6.

Before the August 2003 blackout, MISO was planning to

start operating energy and transmission markets in March

2004. The blackout prompted a review of the market

schedule and postponed the start date to December 2004,

with subsequent revisions to March 1, 2005, and April 1,

2005, to ensure reliable incorporation of grandfathered

agreements and sufficient testing of market systems.

During 2004, MISO resolved many issues of market

design; developed system models to support reliability

and market functions; tested dispatch and market software and accounting and settlement procedures; and allocated transmission rights at the start of the market. Key

events during 2004 included installation of an improved

state estimator to provide MISO with the advanced state

of the art software needed to reliably operate the power

system; development of a Joint Operating Agreement

(JOA) with PJM and development of seams agreements

with MAPP, the Southwest Power Pool (SPP), and TVA;

extensive review and revision of transmission systems

models with transmission owners and market participants; increasingly realistic testing of operational and

market systems through direct testing with market participants; and realistic system tests, where MISO assumed

direct centralized dispatch of participant generators.

Finally, in November, MISO began allocating financial

transmission rights to market participants on the basis of

their current transmission rights, with the goal of ensuring a smooth transition to the MISO market 

environment.

MISO Prepares for 2005 Market Operations
State of the Markets Report • June 2005 81

Midwest (MISO) Electric Market Profile

The Federal Energy Regulatory Commission has encouraged regional state committees as a means of increasing

the effectiveness of regulation and oversight in areas

where federal and state responsibilities overlap. The

Organization of MISO States (OMS) was the first regional

state committee, established in June 2003. It is also the

largest–its members include 14 states and one province of

Canada. The OMS purpose is to coordinate regulatory

oversight among the states, including recommendations

to MISO, the MISO board of directors, FERC, other relevant government entities, and state commissions as

appropriate. During 2004, the OMS was instrumental in

the development of the design of the Day 2 MISO markets, actively participating in stakeholder groups at MISO,

and commenting on the design through filings at FERC.

The OMS structure includes eight working groups that

focus on key aspects of MISO design and operation,

including transmission planning, congestion management and financial transmission right (FTR) allocation,

resource adequacy, market monitoring, and seams issues.

The OMS was particularly effective in assisting the FTR

allocation process to respect both historical contract rights

and the need for competitive market development.

Estimated 2004 annual net revenue from energy for gasfired technologies were below the 5-year average for the

third consecutive year. For a combined cycle, revenues from

energy declined 10% from 2003 and 63% from 2000. For a

combustion turbine, revenues from energy declined from

$8.55/kW-yr in 2000 to $0/kW-yr in 2004. 

We estimate that new gas-fired combustion turbine plants

in the Midwest require $61.57/kW-yr, and gas-fired combined cycle plants require $83.94/kW-yr, to meet debt and

equity requirements. Midwest 2004 net energy revenue estimates were well below these targets, which suggests that

market-based investments in new generation were not

attractive.

0.00

10.00

20.00

30.00

40.00

50.00

60.00

70.00

80.00

90.00

2000 2001 2002 2003 2004

$ / kW-year

CC Net Revenue

CT Net Revenue

CC New Entry Costs

CT New Entry Costs

Cinergy Net Revenue from Energy

Source: FERC/OMOI analysis of Platts day-ahead gas prices for Columbia,

Appalachian and day-ahead power prices for Cinergy. See “Analytic Note on Net

Revenue Calculations” in the Other Material section for details.

NET REVENUE

OMS, the Organization of MISO States
82 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Midwest (MISO) Electric Market Profile

1. Prices are from Platts Megawatt Daily for day-ahead on-peak

delivery at the identified pricing locations.

2. Platts Megawatt Daily, IntercontinentalExchange (ICE) and Dow

Jones prices are for day-ahead on-peak delivery to the Cinergy

Hub. 

3. Data are from NERC’s 2004 ES&D Database and Platts PowerDat

(annual net generation). Statistics are calculated by combining

four NERC Regions: ECAR, MAIN, MAPP and MAAC and removing

corresponding quantities for PJM. Generation capacity excludes

all derates of resources and imports. 

4. ICE on-peak forward and swap prices and volumes are for the

Cinergy Hub and include monthly, dual monthly, quarterly, and

calendar year contracts traded for 2004. 

5. Data from Platts PowerDat, RDI Modeled Production Costs

dataset for calendar year 2003 reflecting self-reporting from all

utility and nonutility electric power generating facilities with

nameplate capacity of 50 MW or more.

6. Data from Energy Information Administration (EIA) Form 860,

Platts NewGen and Platts PowerDat. All generation is summer

capacity unless otherwise indicated.

Disclaimer: This report contains analyses, presentations and 

conclusions that may be based on or derived from the data sources

cited, but do not necessarily reflect the positions or recommendations

of the data providers. 

Source notes

1 In April 2005, the Cinergy Hub replaced the existing Into Cinergy,

the Michigan Hub replaced ECAR North, the Illinois Hub replaced

MAIN South, and the Minnesota Hub replaced MAIN North and

MAPP North.

2 “Impact of Possible Changes in Missouri River Flows on

Nebraska’s Electric Energy Industry,” Nebraska Power

Association, Joint Planning Subcommittee, December 17, 2003, 2.

3 American Wind Association, 

www.awea.org/newsroom/projects2004.pdf.

4 Capacity Additions and Retirements are for calendar year 2004,

based on Platts and EIA net summer capacity estimates and FERC

staff research. They may differ from the Summer Generating

Capacity in the Supply Demand Statistics table. Summer

Generating Capacity may be projected for the summer peak, may

omit some calendar year additions, and may reflect actual

demonstrated capacity and deratings.

5 EIA Form 860, Platts NEWGen, MISO.

6 NERC Energy Supply and Demand database, Midwest Reliability

Organization.

Endnotes
The New England electric market encompasses the New

England sub-region of the Northeast Power Coordinating

Council (NPCC) as designated by the North American Electric

Reliability Council (NERC). In 1999, an independent system

operator–ISO New England (ISO-NE) began operating the

region’s power grid and wholesale electric markets. ISO-NE

now operates a two-settlement spot energy market with locational marginal pricing (LMP), a regional capacity market, a

forward reserve market, and a financial transmission rights

market. Market participants also actively trade electricity bilaterally, often using the ISO-NE Internal Hub as the pricing point.

Average 2004 peak prices for the ISO-NE Internal Hub, also known

as the Mass or Nepool Hub increased 3%–5% over 2003 prices, due

mainly to higher fuel prices. 

The region is currently oversupplied. The 2004 regional reserve

margin increased from 2003 as peak demand fell due to mild temperatures and supply increased slightly with the addition of new

plants. However, northeast Massachusetts/Boston and southwest

Connecticut need generation capacity and transmission additions

to achieve local reliability. These load pockets did not exhibit

materially higher locational prices in 2004, probably because the

costs of expensive units used to ensure resource adequacy and

transmission security in these areas are frequently not eligible to

set the clearing price. Maine, with much more regional generation, had slightly lower average prices.

New England (ISO-NE) Electric Market Profile

State of the Markets Report • June 2005 83

NY

NY

ME

$54.67

NH

$60.57

VT

$61.94

 WCMA 

$61.62

CT

$62.39

NEMA

$60.97

RI

$60.07

SEMA

$59.51

Hub

$61.15

Maine

Vermont

New Hampshire

West-Central Mass

NE Mass/Boston

SE Massachusetts

Connecticut

Rhode Island

Canada

Canada

• The Cold Snap of January 2004

resulted in high prices, reflecting rational behavior by market

participants under severe

weather conditions. All electric

customers were served, but

high prices resulting from the

cold revealed poorly coordinated market rules and incentives

for gas and electricity.

Consequently, ISO-NE changed

its rules to increase coordination between gas and electric

markets and enhance reliability.

• Southwest Connecticut faced

local transmission constraints

that worsened with continued

economic growth. The high

cost of addressing constraints

in the load pocket through mitigation was not reflected in the

price but rather in uplift. The

lack of comprehensive locational prices, reflecting the full cost

of service, sent distorted signals

to customers concerning the

costs they imposed on the grid.

Incentives for market-based

generation and transmission

investments were not provided.

ISO-NE and Northeast Utilities

proposed transmission

upgrades to the southwest

Connecticut system, but these

have been delayed by controversy over cost allocations and

siting.

• Uplift, a make-whole payment

to generators whose bid costs

exceed the locational marginal

clearing price, totaled $334 

million in 2004. Of this, $169

million was the result of units

being committed after the dayahead market closed or dispatched out-of-merit order for

daily reliability or transmission

support. The balance of uplift,

$165 million, was for reliability

(RMR) agreements. The bulk of

the daily uplift occurred in the

NEMA/Boston and Connecticut

zones, which saw 49% of the

day-ahead uplift payments and

87% of real-time uplift. To

decrease daily uplift, the ISO

was developing changes to the

mitigation rules and the dispatch and commitment process.

The ISO also was designing an

ancillary service market to

encourage the addition of quickstart units and market enhancements to capture out-of-merit

dispatch costs in reserve prices.

A number of transmission projects and operational changes

were also in the works, which

should reduce the amount needed for reactive power support.

Focal Points for 2004

Supply Demand Statistics

2003 2004 Exp. 2005

Summer Generating Capacity MW 30,260 31,299 31,504

Summer Peak Demand MW 24,685 24,116 26,355

Summer Reserves MW 5,575 7,183 5,149

Summer Reserve Margin 23% 30% 20%

Annual Net Generation GWh 127,195 129,460

Annual Load GWh 130,776 132,518

Annual Net Exports/Imports GWh (5,441) (4,907)

ISO-NE/Nepool/Mass Hub Prices

2003 2004 5-Year

ISO-NE $57.80 $61.15 $48.69

Platts Megawatt Daily $59.05 $61.47 $48.58

ICE $58.88 $60.69 NA 

Source: Derived from ISO-NE, ICE and Platts data. See source note 2. Source: Derived from Nepool, ISO-NE data. See source note 3.

Source: Dervied from ISO-NE data. See source note 1.

2004 Average Zonal Prices for On-Peak Hours ($ per MWh)
For New England, financial markets consist of both physical forwards and financial swaps. Nymex ClearPort began trading New

England financial swaps in November for December and future

months.

Through the first three quarters of 2004, New England forward

transaction volumes on ICE averaged two-and-a-half times the

swap transaction volumes. Fourth-quarter ICE swap transaction

volumes averaged seven times the volume of forward transactions.

In Nymex ClearPort’s first month of New England trading, a total

volume of 73,600 MWh was traded for December. 

The increase in trading of New England financial products was

consistent with the general trends in electricity trading as more

nontraditional electricity trading entities, such as hedge funds

and banks, have become active in these financial markets, and as

industry credit has improved.

84 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

The above charts illustrate day-ahead (DA) peak bilateral prices

from Platts and the IntercontinentalExchange (ICE) as well as

ISO day-ahead and real-time (RT) LMPs. On January 15, dayahead prices for both ISO-NE and Platts rose to more than $300

per MWh, almost twice as high as the next highest day–January

16. The differences between ISO day-ahead and real-time price

were small throughout most of the year, except during the cold

snap, when the real-time price was $141 per MWh higher on

January 14, and the day-ahead price was $187 higher on January

15. The real-time price was also substantially higher than the dayahead price during two weather events later in the year

(December 6 and December 20). 

New England reached its peak hourly load of 24,116 MW on

August 30. In 2004, the daily peak load hours averaged 17,247

MW. Day-ahead volumes for ISO-NE generally tracked real-time

volumes, but diverged during the cold snap by as much as 11%. In

bilateral trading, Platts reported volumes averaged 378 MW and

peaked on July 28 at 2,250 MW; ICE volumes averaged 5,163 MW

and peaked on June 23 at 24,000 MW. 

New England (ISO-NE) Electric Market Profile

SPOT MARKETS: PRICES AND VOLUMES

FINANCIAL MARKETS: PRICES AND VOLUMES

Daily Average of On-Peak Prices

$0

$20

$40

$60

$80

$100

$120

$140

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

$/MWh

Platts Mass Hub

ICE Mass Hub

ISO Mass Hub

Platts: $315

ICE: $174

ISO: $373

Jan 15 at

Daily Average RT vs. DA On-Peak Prices

-$80

-$60

-$40

-$20

$0

$20

$40

$60

$80

Jan

FebMar

Apr

May

Jun

Jul

AugSep

Oct

NovDec

$/MWh

ISO Mass Hub (RT - DA)

 -$187

 $141

Jan 14 at

Jan 15 at

Source: Derived from ISO-NE, ICE and Platts prices. See source note 4. Source: Derived from ISO-NE prices. See source note 4.

Swaps Prices from Trade Date Forward and Swaps Volume

$0

$20

$40

$60

$80

$100

$120

$140

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

$/MWh

12/15/2003

03/15/2004

06/15/2004

09/15/2004

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

NovDec

GWh

ICE Forward Volume

ICE Swaps Volume

ClearPort Swaps Volume

Source: Derived from ICE and Nymex data. See source note 5. Source: Derived from ICE and Nymex data. See source note 5.
Capacity auctions provide for adequate reserve margins as

well as sending market investment signals. Capacity can

be procured through ISO-NE auctions or through bilateral agreements or self-supply. The ISO-NE capacity markets consist of a supply auction and then a deficiency auction, both for unforced capacity (UCAP). In the supply

auction, load-serving entities can submit price-sensitive

capacity demand bids, whereas capacity resources offer

price-sensitive supply bids. In the deficiency auction,

load-serving entities that have not procured sufficient

resources to meet their capacity requirements must do so

at the cleared auction price. 

Through October, the price in the deficiency auction was

$0.00/kW-month, whereas the average supply auction

price was $0.03/kW-month. For November and

December, the average deficiency auction price was

$0.04/kW-month and the average supply auction price

was $0.02/kW-month. 

Total auction volumes more than doubled from January to

December. Although the supply auction volumes

increased and decreased throughout the year, the deficiency auction volumes increased consistently. By December,

deficiency auction volumes were nine times the volumes

in February, the lowest volume month.

State of the Markets Report • June 2005 85

New England (ISO-NE) Electric Market Profile

$0.00

$0.05

$0.10

$0.15

$0.20

$0.25

$0.30

$0.35

$0.40

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

$/kW-mo

Supply Auction

Deficiency Auction

Weighted Average

Capacity Auction Volume

Source: Derived from ISO-NE data. See source note 6. Source: Derived from ISO-NE data. See source note 6.

Capacity Delists Increase

Load-serving participants in New England, like those in New

York and PJM, must purchase installed capacity (ICAP) from

generators in proportion to the load-server’s share of the system’s peak load. Capacity markets like ISO-NE’s attempt to

maintain adequate generation resources in the region by

requiring such purchases, and by auctioning ICAP. Each auction generates a single clearing price for ICAP. Outside New

England, some generators receive significant revenue from the

capacity market, but prices in New England have been low:

The clearing price in the supply auction was zero in 10 months

in 2004. In November and December, deficiency auction

prices increased to $0.04 and $0.05 per kW-month, respectively. Even the January Supply Auction price of $0.20 per kWmonth was low compared to other regions. By comparison,

PJM’s average 2004 price was $0.51 per kW-month, and New

York’s (outside of New York City) was $1.31 per kW-month.

Faced with low prices, increasing numbers of New England

generators have delisted, or withdrawn from the capacity market, probably to pursue more desirable export opportunities or

to avoid the obligations associated with being an ICAP recipient. A delisted unit is not obligated to participate in New

England’s day-ahead energy market but must offer energy

from that unit in real time. The increase in delistings coincided with increased trading in the capacity deficiency auctions,

for which monthly volumes grew more than ten-fold during

2004.1

0

1,000

2,000

3,000

4,000

5,000

6,000

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

MW

Deficiency Auction

Supply Auction

Capacity Auction Prices

CAPACITY AUCTIONS
86 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

New England (ISO-NE) Electric Market Profile

Capacity and Generation by Fuel and Prime Mover

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Capacity Net Generation

Share of Regional Total (%)

OIL CT

GAS/OIL CT

GAS CT

OIL ST

GAS/OIL ST

GAS/OIL CC

GAS ST

GAS CC

COAL ST

NUCLEAR

WIND

HYDRO

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Capacity Total Generation

Share of Regions Total %

Mirant Corp.

Entergy Corp.

Calpine Corp.

International Power PLC

(ANP)

Dominion Resources, Inc.

NRG Energy, Inc.

Northeast Utilities

FPL Group, Inc.

Exelon Corp.

National Energy & Gas

Transmission, Inc.

Source: Derived from Platts data. See source note 7.

Source: Dervied from Platts data. See source note 7.

In 2003, hydro, wind, nuclear, and coal provided 36% of total

New England capacity and half of net generation. The region

depends on gas-fired combined-cycle units to meet some base

and intermediate loads. In 2003, these units provided 31% of

capacity and 32% of annual net generation.

ISO-NE’s mitigation efforts attempted to stop the effects of

any market conduct that would substantially distort competitive outcomes while avoiding unnecessary interference

with competitive price signals and normal market operations. ISO-NE could impose mitigation only to remedy

conduct that it believed was significantly inconsistent with

competitive conduct, would result in a material change in

one or more prices in the New England Markets or

Operating Reserve payments to a Market Participant, and

was unexplained. ISO-NE used a variety of indices,

screens, and reference prices to identify bids or other conduct that was suspect. If suspicions were raised, the conduct was tested against a threshold to determine whether it

has a “material impact” on prices. If the suspicious conduct appeared to have an impact, the monitor called the

company to determine if the conduct was justified by competitive conditions. If justified, the investigation ended. If

the conduct was not justified, mitigation was implemented

for a period of up to 6 months.

In 2004, ISO-NE mitigated one unit on two days,

December 17 and 18. The mitigation occurred in the

real–time market for a total of about 26 hours. The ISO

explains that mitigation occurred infrequently because the

participants knew what the reference levels and thresholds

were, and tend to tailor their bids to avoid mitigation.

2003 RESOURCE MIX

2003 MARKET CONCENTRATION

As shown, the top 10 owners provided 73% of capacity and 74%

of generation in New England in 2003. Nine of the top 10

providers in New England were independent power producers

or utility affiliates that built or acquired generating assets outside of their traditional service territories. 

In 2004, capacity concentration decreased as lender syndicates

received the keys to more than 3,600 MW of defaulting assets,

most prominently the 2,600 MW Boston Generating asset portfolio. Dominion Resources acquired 2,400 MW of the USGen

New England portfolio. 

Capacity and Generation of Top 10 Companies

Offer Mitigation
State of the Markets Report • June 2005 87

New England (ISO-NE) Electric Market Profile

Net revenue for generators was less than the estimated costs of

entry in New England in 2004 (see “Analytic Note on Net

Revenue Calculations” for details of the net revenue test reported

here). A combined cycle plant could have recovered 59 percent of

the revenue needed to justify the investment in 2004, down from

earlier years. For combined cycle plants, most of the contribution

to net revenue came from the energy market. (Capacity payments

were at or near zero for most of the year and totaled $0.36/kW-yr

for the year as a whole.) A major factor in the decline in net revenues may have been the mild summer weather, which reduced

average prices compared to a normal summer. 

For combustion turbines, the major source of revenue would have

been ISO-NE’s ancillary service market (not included in the figure). ISO-NE’s market monitor estimated that in 2004, a combustion turbine could have received $44/kw-yr from the ancillary

services market, between 66 and 88% of the amount needed to

justify investment.3 A higher net revenue for combustion turbines is consistent with New England’s need for more quick-start

resources.

Using estimates based on Energy Information Administration

(EIA) data, new gas-fired combustion turbines in New England

would require an estimated $63.53/kW-year, and gas-fired combined cycle plants require about $86.76/kW-year to meet debt and

equity requirements. Others’ estimates of entry costs in New

England vary. John J. Reed, at FERC on behalf of ISO-NE, testified that the cost of a new combustion turbine in New England’s

“Rest of Pool” was $92.34/kW-year.4 Reed’s new combustion turbine entry cost estimates varied from $99.16 /kW-year in southwest Connecticut to $87.22 in Maine.

0.00

20.00

40.00

60.00

80.00

100.00

120.00

140.00

2000 2001 2002 2003 2004

$ / kW-year

CC Net Revenue

CT Net Revenue

CC New Entry Costs

CT New Entry Costs

Mass Hub Net Revenue from Energy

Source: Derived from Platts data. See “Analytic Note on Net Revenue Calculations”

in the Other Material section for details. See source note 8.

NET REVENUE

REGIONAL EXPORTS AND IMPORTS

New England was a net importer of electricity for an average of

555 MW in 2004. Eliminating exports over the Cross Sound

Cable, which links Connecticut with Long Island, New

England imported an average of 637 MW in 2004. Power tended to flow out of the region in spring and in early fall, when

capacity margins increased.

Hourly Net Interchange

External Interface Max Hourly Max Hourly Avg Hourly

Exports - MW Imports - MW Net Exports

MW

Hydro Quebec - Highgate 82 218 (130)

Hydro Quebec - Phase I/II 707 1643 (293)

New Brunswick - Keswick 300 678 (151)

New York - Cross Sound Cable 330 50 82

New York - Roseton 1219 1048 (63)

Average Daily Net Interchange

-1,500

-1,000

-500

0

500

1,000

1,500

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

NovDec

Net Exports (MWh)

Source: Derived from ISO-NE data. See source note 9. Source: Derived from ISO-NE data. See source note 9.
88 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

New England (ISO-NE) Electric Market Profile

Generation Additions: In the ISO-NE region, four generation

projects came on line. In Connecticut two additions came on

line—the Milford plant, a 464-MW combined cycle facility, and

Waterside Power, a 60-MW distillate fuel oil facility. Two 6-

MW additions, one in Rhode Island and one in Massachusetts,

also came on line. Capacity additions in 2004 were less than in

the two previous years. Generation retirements in 2004 totaled

343 MW, of which 212 MW are the deactivated reserves at the

Devon plant.5

Seven projects, representing 538 MW, were proposed to be

added between 2005 and 2007.6

Transmission Additions: In 2004, transmission upgrades

totaled about $80 million including 11.1 miles of low voltage

(115kv) transmission costing $4.2 million.

ISO-NE Reliability Costs Rising as RMR Contracts Increase

Reliability must run (RMR) is a contract term that refers to

power generation resources identified by the ISO as necessary for the provision of operating reserve requirements

and adherence to North American Electric Reliability

Council (NERC), Northeast Power Coordinating Council

(NPCC), and Nepool reliability criteria. These units provide power beyond the first contingency reliability criteria

within a region. Most of these units are located in import

constrained areas, such as southwest Connecticut and

Boston, and are run during certain periods to alleviate

transmission constraints and, thus, are likely to have market power at those times. RMR contracts, also known as

reliability agreements, are available to generation units

that are not able to operate profitably. An RMR contract

compensates the unit for its fixed costs. 

In 2004, New England load-serving entities (LSEs) paid

$165 million to cover the fixed costs of generators under

RMR contracts. These are out-of-market payments to generators, which, like the daily reliability/transmission support uplift payments discussed earlier, are not reflected in

market prices. Also like daily uplift, these are side-payments not reflected in the LMP that serve to keep prices in

constrained areas low; in fact, every new RMR contract

essentially lowers the marginal unit in the bid stack and

further reduces prices that occur in the market. 

In 2004, six new RMR contracts became effective to secure

almost 1,437 MW from ISO-NE generators for an annual

fixed cost of $98.9 million. Another $66.4 million in RMR

contracts became effective in January 2005. The ISO estimates that total annual fixed-cost payments to generators

in 2005 for all RMR contracts will be about $345.1 million

for 4,394 MW. This amount does not include the 1,194

MW awaiting FERC approval. Generators outside southwest Connecticut and Boston have begun requesting RMR

status. ISO-NE has stated that bankrupt generators may

not continue to operate without RMR contracts or market

changes such as locational installed capacity (LICAP). 

ISO-NE’s LICAP proposal is intended to improve marketbased indicators for economic addition/retirement decisions and to remedy local reliability issues and remove the

need for RMR contracts. The proposal is pending before

the Commission, which has directed that all RMR contacts

expire when LICAP becomes effective. In the interim,

more New England generating units continue to seek

approval for RMR contracts.

Capacity Additions

-1000

-500

0

500

1000

1500

2000

2500

3000

3500

2002 2003 2004

MW

ISO-NE Additions

ISO-NE Retirements

ISO-NE Mothballed

GENERATION AND TRANSMISSION ADDITIONS AND RETIREMENTS

Source: Derived from ISO-NE, EIA Form 860 and Platts data (summer capacity).
State of the Markets Report • June 2005 89

New England (ISO-NE) Electric Market Profile

1 Analysis of capacity auction volumes and prices; ISO–NE.

2 Robert Ethier, ISO-NE market monitor in a presentation of the

State of the Market to FERC, May 4, 2005.

3 Information provided by ISO New England.

4 Docket No. ER03-563-030.

5 Capacity Additions and Retirements are for calendar year 2004,

based on Platts and EIA net summer capacity estimates and FERC

staff research. They may differ from the Summer Generating

Capacity in the Supply Demand Statistics table. Summer

Generating Capacity may be projected for the summer peak, may

omit some calendar year additions, and may reflect actual

demonstrated capacity and deratings.

6 Information provided by request from ISO-NE.

Endnotes

Source notes

1. Prices are ISO-NE’s day-ahead locational marginal prices for the

zones identified and the Internal Hub. Data located at

http://www.iso-ne.com/smd/operations_reports/hourly.php.

2. Platts Megawatt Daily prices are day-ahead on-peak for the

Massachusetts Hub. IntercontinentalExchange (ICE) prices are

day-ahead on-peak for the Nepool Mass Hub. ISO-NE prices from

March 1, 2003 through 2004 are day-ahead locational marginal

prices for the Internal Hub, data located at http://www.isone.com/smd/operations_reports/hourly.php. ISO-NE prices

before March 1, 2003 are from http://www.isone.com/

Historical_Data/daily_monthly/daily_postmarkets.txt. 

3. Nepool 2004-13 Forecast Report of Capacity, Energy, Loads, and

Transmission (2004 CELT Report) and conversations with ISO-NE

staff. Annual net generation from ISO-NE. Generation capacity

excludes all derates of resources and imports. 

4. Platts Megawatt Daily prices are day-ahead on-peak for the

Massachusetts Hub. ICE prices are day-ahead on-peak for the

Nepool Mass Hub. ISO-NE prices are day-ahead locational marginal prices for the internal Hub, data located at http://www.isone.com/smd/operations_reports/hourly.php. 

5. ICE on-peak forward and swap prices and volumes are for the

Nepool Mass Hub and include monthly, dual monthly, quarterly,

and calendar year contracts traded for 2004. New York

Mercantile Exchange (Nymex) ClearPort on-peak swaps volumes

are for the ISO-NE Internal Hub traded by month. 

6. ISO-NE capacity price and volume information is located at

http://www.iso-ne.com/settlementresettlement/SMD_ICAP/SMD_ICAP/NEPOOL_ICAP_Auction_Rep

ort.xls.

7. Data from Energy Information Administration (EIA) Form 860,

Platts NewGen and Platts PowerDat. All generation is summer

capacity unless otherwise indicated.

8. The analysis is based on Platts Megawatt Daily’s day-ahead onpeak electric prices for the Nepool Mass Hub or, prior to March 1,

2003, the Nepool Trading Point and from Platts Gas Daily’s day

ahead natural gas prices from Tennessee Zone 6. The figure does

not include revenue from capacity or ancillary services. For a

detailed discussion of the calculation method, see “Analytic Note

on Net Revenue Calculations” in the Other Material section of the

Report.

9. Average hourly net interchange data are from the ISO-NE and are

available at http://www.isone.com/

smd/operations_reports/ext_int_actual.php. 

Disclaimer: This report contains analyses, presentations, and conclusions that may be based on or derived from the data sources cited, but

do not necessarily reflect the positions or recommendations of the

data providers. 
90 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

New England (ISO-NE) Electric Market Profile
The New York electric market encompasses the New York

Power Pool (NYPP) subregion of the Northeast Power

Coordinating Council (NPCC), as designated by the North

American Electric Reliability Council (NERC). Late in 1999,

the independent system operator–New York ISO

(NYISO)–began operating the region’s bulk power system and

certain wholesale markets. NYISO operates a two-settlement

spot energy market with locational marginal pricing (LMP), a

regional and locational capacity market, and a financial transmission rights market. Market participants trade electricity

bilaterally through brokers, the IntercontinentalExchange

(ICE) and the New York Mercantile Exchanges (Nymex)

ClearPort, using Zone A (West) as the primary pricing point.

The average 2004 NYISO total price (for energy and ancillary

services in all hours) increased 0.4% over 2003.1

The New York City metropolitan area (NYC) and Long Island

(LI) are areas of concentrated demand. Both localities have

requirements for installed generating capacity more stringent

than the rest of the region to ensure reliability of service. In 2004,

there was enough installed capacity to meet these requirements in

NYC and LI, and there was surplus capacity elsewhere in the

region. Reserve margins increased in 2004 as new plants entered

commercial operation in NYC and elsewhere, and mild summer

weather reduced peak loads. The map shows that prices in NYC

(Zone J) and LI (Zone K) were significantly higher than elsewhere

in the New York region. The higher prices resulted from a lack of

inexpensive local generation and limited transmission capacity in

those localities.

New York (NYISO) Electric Market Profile

State of the Markets Report • June 2005 91

Zone A • West

Zone B • Genesee

Zone C • Central

Zone D • North

Zone E • Mohawk Valley

Zone F • Capital

Zone G • Hudson Valley

Zone H • Millwood

Zone I • Dunwoodie

Zone J • New York City

Zone K • Long Island

Zone E

$57.43

VT

MA

Canada

PA

NJ

Zone F

$60.41

Zone C

$55.72 Zone A

$52.22

$55.54

Zone G

$60.96

Zone B

$55.21

Zone H

H $61.48

I

J K

B

B

Zone I

$62.30 Zone K

Zone J $72.23 $76.41

D

• Cold weather brings high

prices, loads. NYISO set a 

winter peak load record on

January 15, 2004, (25,262

MW) and again on December

20, 2004 (25,541 MW).

Natural gas prices were high

on both occasions

($11.64/MMBtu average during January and $7.80/MMBtu

during December) because of

gas delivery limitations in the

northeastern United States.

Some generators were unable

to procure gas during these

cold weather periods, but

New York’s substantial stock

of dual-fuel generators

buffered it from significant

reductions in generation.

• NYC mitigation changes. In

May NYISO changed how

AMP mitigates bids in the 

day-ahead market in New York

City. Mitigation dropped from

about 30% of all unit-hours 

(a unit-hour is one generator

for 1 hour) to less than 10%. 

One refinement allows NYISO

to mitigate bids for particular

hours, rather than for an

entire day, when bidding

thresholds are exceeded.

Despite the change, mitigation

continued to be commonplace

in New York City; elsewhere 

in the state, no mitigation

occurred.

• Reliability planning process

approved. In December FERC

approved NYISO’s reliability

planning process, which 

will look ahead 10 years to

identify reliability needs in 

the bulk power system,

report annually on the needs,

evaluate proposed marketbased and regulatory 

solutions, and track implementation progress.

Participants continued work

on a planning process to 

evaluate economic needs of

the bulk power system.

Focal Points for 2004

Supply Demand Statistics

2003 2004 Exp. 2005

Summer Generating Capacity MW 37,094 38,111 37,548

Summer Peak Demand MW 30,333 28,432 31,962

Summer Reserves MW 6,761 9,679 5,586

Summer Reserve Margin 22% 34% 17%

Annual Net Generation GWh 158,015 160,210 164,050 

NYISO Hudson Valley (Zone G) Prices

2003 2004 5-Year

ISO $61.26 $60.96 $53.28

Platts $61.73 $61.74 $50.26

Source: Derived from NYISO and Platts data. See source note 1. Source: Derived from NYISO data. See source note 2.

Source: Derived from day-ahead NYISO prices. 

2004 Average Zonal Prices for On-Peak Hours ($ per MWh)
The western zone (A) had the most actively traded financial product for New York on both the ICE and Nymex ClearPort trading

platforms. Forward prices increased through June and declined

somewhat during the second half of 2004. Trading volumes

increased noticeably in December, exceeding 10,000 GWh for the

first time. Financial trading for the Hudson Valley (G) and New

york City (J) remained low.

92 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

The figure “Daily Average of On-Peak Prices” (above) shows

day-ahead peak bilateral prices (from Platts and ICE) and

NYISO day-ahead and real-time location-based marginal prices

(LBMPs.) Prices were highest during January because of high

cold-weather demand and high natural gas prices. Mild summer

weather kept loads and prices moderate. During December high

gas prices and cold weather raised prices modestly, but many generators burned oil instead of gas, which moderated the effect of

fuel costs on electricity prices.

New York reached its peak hourly load of 28,433 MW on

June 9, 8% below the 2001 historic peak (30,983 MW). In

2004, daily peak load hours averaged 20,447 MW. In bilateral trading, ICE Western New York (Zone A) volumes averaged 3,455 MW and peaked on May 12 at 18,400 MW.

New York (NYISO) Electric Market Profile

SPOT MARKETS: PRICES AND VOLUMES

FINANCIAL MARKETS: PRICES AND VOLUMES

Daily Average of On-Peak Prices

$0

$20

$40

$60

$80

$100

$120

$140

Jan

FebMar

Apr

May

Jun

Jul

AugSep

Oct

NovDec

$/MWh

Platts West Platts Hudson V. Platts NYC

ICE West ISO West ISO Hudson V.

ISO NYC

Platts NYC: $200

ISO NYC: $204

Differences Between Real Time and Day-ahead Prices

-$80

-$60

-$40

-$20

$0

$20

$40

$60

$80

Jan

FebMar

Apr

May

Jun

Jul

AugSep

Oct

NovDec

$/MWh

ISO West

ISO Hudson V.

ISO NYC

ISO West: $94

ISO Hudson V. : 

$104

ISO NYC: -$88

ISO NYC: $81

Source: Derived from NYISO and Platts data. See source note 3. Source: Derived from NYISO data. See source note 3.

Western New York Swaps Prices from Trade Date Various New York Swaps Volume

$0

$20

$40

$60

$80

$100

$120

$140

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

$/MWh

12/15/2003

03/15/2004

06/15/2004

09/15/2004

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

Jan

FebMar

Apr

May

Jun

Jul

AugSep

Oct

Nov

Dec

MWh (thousands)

ICE West ICE Hudson V.

ICE NYC ClearPort West

ClearPort Hudson V. ClearPort NYC

Source: Derived from ICE data. See source note 4. Source: Derived from ICE and Nymex data. See source note 4.
Capacity markets provide for adequate reserve margins and

encourage investment in generating capacity. In New York, loadserving entities (LSEs) may procure capacity through NYISO’s

capacity market or through bilateral agreements; they may also

supply it themselves. NYISO’s capacity market consists of a semiannual strip auction of six month supplies, a monthly auction for

individual months remaining in the six month season, and a

monthly spot auction for the following month. All capacity trading and requirements are in unforced capacity (UCAP). In the

strip and monthly auctions, capacity resources make price-sensitive offers and LSEs submit price-sensitive bids, which are

matched to give a single clearing price. The spot auction differs:

NYISO is unique in setting spot auction prices with a demand

curve, a sliding price scale that declines as capacity supply moves

from shortage to surplus. NYISO submits bids, at a price determined from the demand curve, on behalf of LSEs that have not

procured all of their capacity obligations before the spot auction.

LSEs in New York City and Long Island must acquire locational

capacity (capacity from generators in those locations), so three

distinct capacity products–New York City, Long Island, and Rest

of State–are traded.

NYC’s constrained transmission and relatively tight supply led to

high NYC capacity prices. Most New York City generators have

regulated caps on their capacity offers, causing summer capacity

prices to clear in a narrow range of $11.15 to $11.42/kW-month.

Winter capacity cleared between $5.60 and $7.12. Volume in the

NYISO capacity market was a significant fraction of the NYC

requirement (8,445 MW for summer) because most NYC generators must offer through the NYISO market. Strip volumes for

winter 2004–05 increased substantially over winter 2003–04. 

State of the Markets Report • June 2005 93

CAPACITY AUCTIONS

New York (NYISO) Electric Market Profile

NYC Capacity Auction Prices

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

$14.00

$16.00

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

$/kW-mo

Strip

Monthly

Deficiency/Spot

Weighted Average

NYC Capacity Auction Volume

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

MW

Deficiency/Spot

Monthly

Strip

Source: Derived from NYISO data. See source note 5. Source: Derived from NYISO data. See source note 5. 

NYISO faced several challenges to its software systems in 2004.

A long-standing error in a database of financial transmission

rights (called Transmission Congestion Contracts in New

York) was found to have distorted their value in auctions as far

back as winter 2002, forcing NYISO into a complex redistribution of revenue and a legal settlement with affected participants. A major redesign of NYISO’s real-time market system,

known as SMD 2, was repeatedly delayed as software designers missed deadlines and extensive market trials were run and

analyzed. (When SMD 2 began operating in February 2005, it

produced erratic real-time prices for a few weeks while problems were addressed.) An error also was discovered in the

AMP system that mitigates real-time bids in New York City.

NYISO continued to improve its import-export scheduling

system and a system to allow third-party scheduling of capacity on the Cross Sound Cable by June 2005.2 

Software Problems Reflect Market Complexities, Vulnerabilities
94 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Statewide capacity prices ranged from $0.60 to $1.75 per kWmonth, as a consequence of ample supplies in the region outside

of NYC and LI. NYISO market volumes averaged about 7,900

MW monthly, compared with the statewide requirement of

35,585 MW (summer), and were about evenly divided among the

strip, monthly, and spot auctions.

New York (NYISO) Electric Market Profile

NY Capacity Auction Prices

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

$14.00

$16.00

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

NovDec

$/kW-mo

Strip

Monthly

Deficiency/Spot

Weighted Average

NY Capacity Auction Volume

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

MW

Strip Monthly Deficiency/Spot

Source: Derived from NYISO data. See source note 5. Source: Dervied from NYISO data. See source note 5. 

NYISO may mitigate offers for energy, start-up costs, minimum generation, reserves, and regulation of output. It

employs a “conduct-and-impact” scheme, meaning it mitigates only those offers that exceed specified thresholds

(“conduct” test) and that would, if not mitigated, raise

prices by a specified amount (“impact” test). The conduct

test measures offers against a pre-existing reference level

assigned to each generator based on its offer history, price

history at its location, or a level negotiated with NYISO.

Reference levels adjust for changes in fuel prices. 

For example, a generator’s energy offer would fail the conduct test if it exceeded its reference level by $100/MWh or

300% (whichever was lower.) The same offer would fail the

impact test if it would cause a price increase of $100/MWh

or 200% (whichever was lower), and it would be mitigated,

meaning it would be lowered to its reference level.

These thresholds apply everywhere except in New York

City (Zone J). The city’s large demand, constrained transmission, and concentrated generation ownership are

judged to give each generator significant market power, so

NYISO uses much tighter mitigation thresholds (ranging

from about $3 to $38 in February 2005). All mitigation in

2004 occurred in New York City, where about 10% of unithours in the day-ahead market and about 20% of unit-hours

in the real-time market were mitigated.3

Offer Mitigation
State of the Markets Report • June 2005 95

New York (NYISO) Electric Market Profile

Capacity and Generation by Fuel and Prime Mover

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Capacity Net Generation

Share of Regional Total (%)

OIL CT

GAS/OIL CT

GAS CT

OIL ST

GAS/OIL ST

GAS/OIL CC

GAS ST

GAS CC

COAL ST

NUCLEAR

WIND

HYDRO

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Capacity Net Generation

Share of Regions Total %

AES Corp.

Consolidated Edison Co.

of NY, Inc.

Mirant Corp.

Dynegy, Inc.

Constellation Energy

Group, Inc.

Reliant Energy, Inc.

Entergy Corp.

NRG Energy, Inc.

New York Power Authority

Keyspan Corp.

Source: Derived from Platts data. See source note 6.

Source: Derived from Platts data. See source note 6.

In 2003, hydro, wind, nuclear, and coal constituted 39% of total

New York capacity and provided almost two-thirds of net generation. Dual fuel (gas/oil) generators provided 23% of the capacity

and contributed 16% of annual net generation. Gas-fired combined–cycle units provided 17% of capacity and 15% of annual

net generation. 

2003 RESOURCE MIX

2003 MARKET CONCENTRATION

The top 10 companies owned 81% of capacity and 83% of generation in New York during 2003. Eight of those owners were independent power producers or utility affiliates that built or acquired

generators outside of their traditional service territories. One was

utility Consolidated Edison of New York and one was the New

York Power Authority (NYPA), a state entity that provides lowcost power to state businesses, owns about a third of the

high–voltage transmission system, and, with the New York State

Energy Research and Development Authority (NYSERDA), promotes energy efficiency and clean energy. Major utilities were

required to divest their generating assets when retail markets

were restructured; they now serve load by buying supply bilaterally or through the ISO. (Consolidated Edison retained 688 MW

of generation that is part of its steam supply system.)

Capacity and Generation of Top 10 Companies

REGIONAL EXPORTS AND IMPORTS

In 2004, NYISO was a net importer of energy, importing 1,697

MW in an average hour. Most imports came from PJM and

Ontario. NYISO was a net exporter of energy 2.5% of the time

during the year. NYISO net exports were to ISO-NE only.

Average Hourly Interchange

External Interface Max Max Avg 

Exports - MW Imports - MW Net Exports

(Imports) MW

Hydro Quebec (HQ) 1,001 1,325 (97)

New England (ISO-NE) 1,030 1,219 54

Ontario (IESO) 1,731 2,400 (798)

PJM 2,656 2,807 (856)

Average Daily Net Interchange

-4,500

-4,000

-3,500

-3,000

-2,500

-2,000

-1,500

-1,000

-500

0

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

NovDec

Net Exports (MWh)

Source: Derived from NYISO data. See source note 7. Source: Derived from NYISO data. See source note 7.
96 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

New York (NYISO) Electric Market Profile

In New York, revenues from capacity payments can be as significant as revenues from energy sales. When 2004 net revenue estimates from capacity are combined with energy, market-based

investments, particularly in New York City, begin to appear

attractive. 

Annual net revenue from energy for gas-fired technologies

declined from 2003 in both the Hudson Valley (Zone G) and New

York City (Zone J). For a combined cycle in New York City, revenue from energy declined 12% from 2003, but remained 2%

above the four-year average. In the Hudson Valley, combined

cycle revenue from energy declined 14% from 2003 (28% from

2001) and was below the four-year average for the second consecutive year. For combustion turbines, revenue from energy in both

areas fell to a four-year low.

Using estimates based on Energy Information Administration

(EIA) data, new gas-fired combustion turbines in New York

would require an estimated $63.53/kW-year, and gas-fired combined cycle plants require about $86.76/kW-year to meet debt and

equity requirements. Others’ estimates of entry costs in New

York vary. Levitan & Associates, Inc., in an independent study for

the NYISO, estimated that the new entry cost in New York City

was $87/kW-year for combustion turbines and $176/kW-year for

combined cycles.4

New York Electric Market Profile

0.00

20.00

40.00

60.00

80.00

100.00

120.00

140.00

160.00

2001 2002 2003 2004

$ / kW-year

CC Net Revenue

CT Net Revenue

CC New Entry Costs

CT New Entry Costs

Zone G Net Revenue from Energy

Source: Derived from Platts data. See “Analytic Note on Net Revenue Calculations”

in the Other Material section for details. See source note 8.

0.00

20.00

40.00

60.00

80.00

100.00

120.00

140.00

160.00

2001 2002 2003 2004

$ / kW-year

CC Net Revenue

CT Net Revenue

CC New Entry Costs

CT New Entry Costs

Zone J Net Revenue from Energy

Source: Derived fromPlatts data. See “Analytic Note on Net Revenue Calculations” in

the Other Material section for details. See source note 8.

NET REVENUE

Net Energy Net Capacity Total Revenue

$/kW-yr $/kW-yr $/kW-yr

Upstate

CC 55.49 16.65 72.14

CT 0.38 16.65 17.03

NYC

CC 112.12 135.25 247.37

CT 20.75 135.25 156.00

Source: Derived from NYISO data. See “Analytic Note on Net Revenue Calculations” in

the Other Material section for details. See source note 8.

Regional Net Revenues from Energy and Capacity
State of the Markets Report • June 2005 97

New York (NYISO) Electric Market Profile

The New York Power Authority (NYPA) and Long Island

Power Authority (LIPA) actively solicited private power

investment in New York. In June 2004, NYPA released a

request for proposals (RFP) seeking as much as 500 MW of

New York City capacity and energy supplies. NYPA expects

that it will need the additional supplies once its Charles

Poletti Power Project, an 875-MW, oil- and natural-gasfueled facility, is shut down, likely in 2008, to meet a regulatory agreement to reduce emissions in the city. The June

RFP drew more than 30 bids from market participants,

including bids based on generation and also on proposed

transmission projects such as PSEG Cross Hudson,

Conjunction, and Astoria Energy. PSEG withdrew after the

Exelon-PSEG merger was announced. Entergy, Morgan

Stanley Capital Group, and Zilkha Renewable Energy (now

owned by Goldman Sachs) were selected to provide energy

under the RFP for NYPA’s governmental customers in New

York City. Because the recent awards only included energy,

NYPA announced a new RFP seeking as much as 500 MW

of in-city capacity. In addition to RFPs, NYPA was apparently willing to review offers to purchase the small clean

power plants that NYPA built in 2002 as part of the Power

NOW! program. NYPA has privatized assets in the past; in

2000, it sold two nuclear plants in the largest sale of a public

asset to a private company in state history.

In January 2004, LIPA solicited bids for combined-cycle

generators to be in service in summer 2005, citing growth in

peak demand. Two 79.9-MW units were selected, one each

by Calpine and Pinelawn Power. In September 2004, the

LIPA board approved a 20-year agreement for transmission

capacity on the proposed Neptune Cable, a 660-MW

HVDC underwater cable between Long Island and New

Jersey. The cable will be privately financed and owned. A

20-year contract from LIPA underwrote another merchant

transmission project, the Cross Sound Cable, which

resumed operation in 2004 after permitting delays.

Generation Additions. Three generating plants with a total summer capacity of 1,258 MW came on line in 2004. The largest is

Athens, a 938-MW combined–cycle plant in Zone F (Capital)

near Albany. The project cost for this independent power plant

was $815 million. KeySpan Ravenswood, a 222-MW

combined–cycle plant, is located in NYC (Zone J) and also came

on line in 2004. All of the new generation is gas-fired;

Ravenswood can also burn oil. Three plants totaling 170 MW

retired in 2004. Nine proposed projects totaling 5,030 MW were

scheduled to be added between 2005 and 2007.5

Transmission Additions. No substantial transmission additions

were completed during 2004. The previously completed Cross

Sound Cable Interconnector, a privately owned, 330-MW high

voltage, direct current (HVDC) line between Long Island and

Connecticut, resumed operation in 2004. The proposed constellation project (HVDC) from Albany to New York City failed. Four

transmission projects were proposed to enter service in 2005–07,

including a 36-mile HVDC line from Sayerville, N.J., to W. 49th

Street in Manhattan. A proposed seven-mile HVDC line from

Bergen, N.J., to W. 49th Street was withdrawn by PSEG after its

proposed merger with Exelon was announced.6

Capacity Additions

-400

-200

0

200

400

600

800

1000

1200

1400

2002 2003 2004

MW

NYISO

Additions

NYISO

Retirements

NYISO

Mothballed

GENERATION AND TRANSMISSION ADDITIONS AND RETIREMENTS

Source: Derived from NYISO, EIA , and Platts data. See source note 9.

Power Authorities Boost Private Investment in New York Power Market
98 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

New York (NYISO) Electric Market Profile

1. Platts Megawatt Daily and NYISO prices are day-ahead on-peak for

NYISO Zone G. For NYISO prices see

http://www.nyiso.com/oasis/index.html?wp=damlbmpzonal.

2. Data are from NYISO’s monthly reports, summer 2003 Operating

Study, 2005 NYCA Forecasted Peak Load, and preliminary data.

Summer reserves and summer reserve margins are derived.

Generation capacity excludes all derates of resources and imports.

3. Platts Megawatt Daily prices are day-ahead on-peak for Zone J. ICE

prices are day-ahead on-peak for Zone A. NYISO prices include dayahead and real-time on-peak for zones A, G and J. NYISO dayahead prices are located at

http://www.nyiso.com/oasis/index.html?wp=damlbmpzonal and

real-time prices at

http://www.nyiso.com/oasis/index.html?wp=rttwilbmpzonal.

4. ICE on-peak forward and swap prices and volumes are for zones A,

G and J and include monthly, dual monthly, quarterly, and calendar

year contracts traded for 2004. New York Mercantile Exchange

(Nymex) ClearPort on-peak swaps volumes are for zones A, G and J

and are traded by month. 

5. NYISO capacity price and volume information is located at

http://www.nyiso.com/markets/icapinfo.html.

6. Data from Platts PowerDat, RDI Modeled Production Costs dataset

for calendar year 2003, reflecting self-reporting from all utility and

non-utility electric power generating facilities with nameplate

capacity of 50 MW or more and NYISO 2004 load and capacity information.

7. Average hourly net interchange data are from the NYISO. 

8. The analysis is based on Platts Megawatt Daily’s day-ahead onpeak electric prices for NYISO’s Zones G or J as applicable and from

Platts Gas Daily’s day-ahead natural gas prices from Transco Zone 6

(NY). The figure does not include revenue from capacity or ancillary

services. For a detailed discussion of the calculation method, see

“Analytic Note on Net Revenue Calculations” in the Other Material

section of the Report.

9. Data from NYISO, Energy Information Administration (EIA) Form

860, Platts NewGen and Platts PowerDat. All generation is summer

capacity unless otherwise indicated.

Disclaimer: This report contains analyses, presentations, and conclusions that may be based on or derived from the data sources cited, but

do not necessarily reflect the positions or recommendations of the

data providers. 

1 NYISO monthly reports, December 2003 and December 2004. 

All prices are in nominal dollars unless noted.

2 FERC Order Accepting Filing and Accepting Tariff Revisions, Docket

No. EL04-110-000 and others (July 22, 2004); NYISO.

3 NYISO Market Administration and Control area tariff, attachment

H; NYISO Technical Bulletin 67; http://www.nyiso.com/markets/mktmon.html; NYISO December 2004 monthly report.

4 Levitan & Associates Inc. letter to NYISO Re: ICAP Demand Curve

– Capital Cost Details and Update, September 1, 2004.

5 EIA Form 860 and NEWGen and consulting sources, NYISO 2004

load and capacity data. Capacity Additions and Retirements are

for calendar year 2004, based on Platts and EIA net summer

capacity estimates and FERC staff research. They may differ from

the Summer Generating Capacity in the Supply Demand Statistics

table. Summer Generating Capacity may be projected for the

summer peak, may omit some calendar year additions, and may

reflect actual demonstrated capacity and deratings.

6 NYISO load and capacity data 2003 and 2004; press reports.

Endnotes

Source notes

New York Electric Market Profile
The Northwest electric market encompasses the Northwest

Power Pool Area (NWPP) subregion of the Western

Electricity Coordinating Council (WECC) as designated by the

North American Electric Reliability Council (NERC). The electric grid is dispatched by 16 control areas in coordination with the

WECC’s Pacific Northwest Reliability Coordinator. No markets

are administered by independent system operators (ISOs) or by

regional transmission organizations (RTOs). Wholesale market

participants, however, utilize physical trades at the CaliforniaOregon Border (COB) Hub and both physical and financial trades

at the Mid-Columbia Hub. Average 2004 peak prices for the MidColumbia Hub increased 10% from 2003.

The region relies on hydroelectric production for approximately

two-thirds of its electricity needs. In most years, the Northwest

sells surplus power into California and the Southwest. The largest

seller of wholesale power is the Bonneville Power Administration

(BPA), which meets approximately 44% of the region’s firm energy supply from resources under its control, primarily the federal

hydroelectric dams in the Northwest.1 In 2004, the Northwest

received below-normal precipitation. Accordingly, Northwest

utilities reported reduced hydro generation and reduced surplus

power sales.2 Nonetheless, when taken together, hydro, fossil

fuels, nuclear energy, and renewable resources, were adequate to

provide electricity in excess of in-region needs. The Northwest

exported electrical energy to California and the Southwest in all

12 months of 2004.3 

Northwest Electric Market Profile

State of the Markets Report • June 2005 99

NWPP

NERC Subregion

Mid-Columbia

$44.53

MT

CO

CA

AZ

California -Oregon Border

$49.08

NM

NV

UT

ID WY

OR

WA

• The driest five-year stretch

since 1929, according to the

BPA, occurred in the Northwest

as it experienced its fifth consecutive year of below-normal

water supplies. The belowaverage water conditions made

it difficult for Northwest utilities

to meet revenue projections

from hydroelectric power sales.

Utility production and market

purchasers relied on increased

generation from coal and natural gas to make up for the

reduced hydro production. 

• Surplus generation was forecast

for the region through 2010 as

the Northwest Power and

Conservation Council (NWPCC)

released its draft “Fifth Power

Plan.” The forecast was based

on several factors including a

reduction in demand that started in 2001 (see “Aluminum

smelter demand for electricity

remained low in 2004”), modest load growth, and more than

4,500 MW of new generation

since 2000.

• Regulatory uncertainties have

made industry participants

reluctant to build new transmission facilities, according to

a Rocky Mountain Area

Transmission Study (RMATS).

RMATS stakeholders and the

governors of Wyoming and

Utah expressed interest in

building transmission to use

regional coal and wind power

resources for local power

needs and for sale to other

parts of the western interconnection.

• Independent transmission. In

December, Grid West participants adopted developmental

bylaws. Northwestern transmission stakeholders, including

nine utilities, negotiated a proposal to develop an independent transmission provider for

much of the region. Grid West

would succeed the previous

RTO West effort and encompass the transmission systems

of utilities in Washington,

Oregon, Idaho, Montana,

Nevada, Utah, and Wyoming.

Membership in the new organization would be voluntary to

plan and manage key operational and selected commercial

functions of the regional grid.

• PGE sale issues. Oregon Electric

LLC (a holding company consisting of Texas Pacific Group, a

private investment firm, and

three northwest business leaders) applied at the Oregon PUC

(OPUC) to purchase Portland

General Electric (PGE) for $1.4

billion and to assume existing

PGE debt of $1.1 billion. (OPUC

approved the sale of PGE to

Enron in 1997 with ring fencing

restrictions that helped keep

PGE from forced bankruptcy in

2001.)4 OPUC denied the application in March 2005.

Focal Points for 2004

2003 2004 Exp. 2005

Winter Generating Capacity MW 54,802 57,101 54,645

Winter Peak Demand MW 35,456 39,710 38,804

Winter Reserves MW 19,346 17,391 15,841

Winter Reserve Margin 55% 44% 41%

Annual Load GWh 219,582 223,148 226,744

Mid-Columbia Hub Prices

2003 2004 5-Year

Platts $40.73 $44.54 $75.59

ICE $40.42 $44.54 NA 

Dow Jones $40.74 $44.53 NA

Source: Derived from Dow Jones, IntercontinentalExchange (ICE), and Platts data.

See source note 2. Source: Derived from WECC data. See source note 3.

Source: Derived from Dow Jones data. See source note 1.

2004 Average Hub Prices for On-peak Hours ($ per MWh)

Supply Demand Statistics
For the Northwest, financial markets consist of both physical forwards and financial swaps. ICE began clearing Mid-Columbia

financial swaps in August. The New York Mercantile Exchange

(Nymex) ClearPort began trading Mid-Columbia financial swaps

in June for July and future months. 

Although ICE and Nymex ClearPort both traded Mid-Columbia

financial swaps, the volumes of financial trading of these products

remained low as compared with the ICE physical Mid-Columbia

product. Physical trading on ICE was highest for the third-quarter

products. The trading of physical products for the fourth quarter

was 15% lower than for the first quarter and more than 30%

lower than for the third quarter.

100 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Day-ahead peak bilateral prices are illustrated from Dow Jones,

IntercontinentalExchange (ICE), and Platts. Northwest prices

followed the annual pattern of decrease in price with increased

streamflow and hydro production during the spring runoff season

(normally the highest runoff occurs in May and June). During

this period substantial surplus power was available to the western

market. 

In bilateral trading for the California-Oregon Border (COB), ICE

volumes averaged 8,156 MW and peaked for December 17 and 18

at 30,400 MW; Platts-reported volumes averaged 591 MW and

peaked on December 7 at 1,825 MW. In bilateral trading for MidColumbia, ICE volumes averaged 23,626 MW and peaked for

June 11 and 12, and for October 19 through 21, at 72,000 MW;

Platts-reported volumes averaged 2,079 MW and peaked on July 2

and 3 at 4,250 MW.

Northwest Electric Market Profile

SPOT MARKETS: PRICES AND VOLUMES

FINANCIAL MARKETS: PRICES AND VOLUMES

CA-OR Border Daily Average of On-Peak Prices 

$0

$20

$40

$60

$80

$100

$120

$140

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

$/MWh

Platts COB

ICE COB

Dow Jones COB

Mid-Columbia Daily Average of On-Peak Prices

$0

$20

$40

$60

$80

$100

$120

$140

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

$/MWh

Platts Mid-Columbia

ICE Mid-Columbia

Dow Jones Mid-Columbia

Source: Derived from Platts, ICE and Dow Jones data. See source note 4. Source: Derived from Platts, ICE and Dow Jones data. See source note 4.

Mid-Columbia Forward Prices from Trade Date Mid-Columbia Forward and Swaps Volume

$0

$20

$40

$60

$80

$100

$120

$140

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

$/MWh

12/15/2003

03/15/2004

06/15/2004

09/15/2004

0

500

1,000

1,500

2,000

2,500

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

MWh (000)

ICE Forward Volume

ICE Swaps Volume

ClearPort Swaps

Source: Derived from ICE data. See source note 5. Source: Derived from ICE and Nymex data. See source note 5.
State of the Markets Report • June 2005 101

Northwest Electric Market Profile

In December, the Northwest Power and Conservation

Council (NWPCC) released its draft of the “Fifth Power

Plan.” In its review, the NWPCC recounted regional transmission issues that have been identified since their “1996

Comprehensive Review of the Northwest Energy System.”

These issues include the need for better management of

power flows and available transmission capacity, for

improved grid planning and expansion, and the need to

address the competitive advantages that various control

area operators possess over competing generation owners.

Such large issues support regional coordination efforts, the

NWPCC concluded.6 The Regional Representative Group

of Grid West laid out other Northwest transmission problems including difficulty managing unscheduled flow;

inability to monitor wholesale electricity markets, and

transaction and rate pancaking (i.e., contracting, scheduling, and paying for the fixed costs of multiple transmission

segments on a volumetric basis to complete a sale); and

complexity and potential reliability concerns as a consequence of the proliferation of control areas.7

Capacity and Generation by Fuel and Prime Mover

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Capacity Net Generation

Share of Regional Total (%)

OTHER

OIL CT

GAS/OIL CT

GAS CT

OIL ST

GAS/OIL ST

GAS/OIL CC

GAS ST

GAS CC

COAL ST

NUCLEAR

WIND

HYDRO

Source: Derived from Platts data. See source note 6.

In 2003, hydro, wind, nuclear, and coal totaled 90% of total

Northwest capacity and provided 91% of net generation. The

region depends primarily on hydro resources, which made up

more than two-thirds of total capacity and provided more than

half of the annual generation in 2003.

2003 RESOURCE MIX

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Capacity Net Generation

Share of Regions Total (%)

TransAlta Corp.

Avista Corp.

Puget Energy, Inc.

The Yakama Nation

Portland General Electr

Seattle City Light

PUD No. 1 of Chelan

County

IDACORP, Inc.

Scottish Power Plc

Bonneville Power

Administration

Source: Derived from Platts data. See source note 6.

2003 MARKET CONCENTRATION

The top 10 owners provided 82% of capacity and 77% of generation in the Northwest in 2003.5 Nine of the top 10 generation

owners were regional utilities, their affiliates, or large municipals and cooperatives. Many of the largest suppliers of retail

load were also the largest owners of generation and thus able to

cover much of their load through self-supply. In 2004, capacity

concentration was little changed as three, large (greater than 25

MW) power plants came on line: Plant capacity totaled approximately 341 MW, or less than 1% of the region’s total capacity.

Capacity and Generation of Top 10 Companies

Northwest Transmission Issues Revisited in 2004
102 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Northwest Electric Market Profile

In 2004, 363 MW of generation (all gas-fired) and five new transmission projects were added in the Northwest region.8

Generation Additions.In the Northwest region, three, large generation projects came on line. Two were independent power producer projects with a combined generating capacity of 342 MW.

In Utah, the Nebo Power Station (a 121 MW Combined Cycle

plant) began operation in June 2004. In August 2004, the

Goldendale Energy Center (a 221 MW combined cycle plant)

came on line. No retirements were reported.9 Capacity additions

in 2004 were less than in the two previous years. 

Transmission Additions. Five major transmission projects were

completed in the Northwest, representing approximately 309

miles of transmission line. In May, the Falcon to Gondor 345 kV

transmission project was completed in Sierra Pacific Power’s service area– a 180-mile line across northeastern Nevada. The 84-mile

Grand Coulee-Bell 500 kV transmission line also was completed,

BPA’s largest transmission project in the past 20 years. The three

other projects were completed in PacifiCorp’s service territory.10

Capacity Additions

-500

0

500

1000

1500

2000

2002 2003 2004

MW

NW Additions

NW Retirements

NW Mothballed

GENERATION AND TRANSMISSION ADDITIONS AND RETIREMENTS

Source: Derived from EIA and Platts data. See source note 7.

Aluminum Smelter Demand for Electricity Remained low in 2004

Electricity demand from aluminum smelting plants, which

historically consumed up to 15% of the region’s electricity

demand, remained modest in 2004. Cost pressures on aluminum production from world-wide competition and

older, less efficient smelters in the Northwest kept production low. Aluminum smelting in the United States is one of

the industries most sensitive to electricity prices, as electricity makes up approximately one-third of the production

cost.

During the early 1980s, 10 aluminum plants accounted for

up to approximately 3,100 average megawatts of the region’s

load. Northwest aluminum production decreased in the late

1980s and 1990s, with electricity needs decreasing from

approximately 2,500 average megawatts down to 2,000 average megawatts, as Northwest power prices rose and more

efficient aluminum plants came on line throughout the

world. The Northwest smelters became “swing” plants,

increasing production when aluminum commodity prices

were favorable in world markets.

During the western energy crisis in 2000 and 2001, the

region faced tight electricity supplies triggered by load

growth, “under-investment in generation and conservation

resources,” and poor hydroelectric conditions starting in the

spring of 2000. To help lower electricity demand, and to

avoid purchasing high-priced electricity from the wholesale

markets, BPA renegotiated its contracts and was able to buy

back power from the aluminum smelters. All the smelters

either reduced or ceased production. Electricity demand

from the aluminum smelters decreased during 2001 to fewer

than 500 average megawatts.

Seven of the region’s 10 aluminum smelters remained

closed; the rest operated at reduced levels. During 2004, electricity demand for aluminum remained at approximately

500 average megawatts.

World aluminum prices rose 18% in 2004, but Northwest

stakeholders expected electricity prices to stay higher than

what Northwest aluminum plants require to operate profitably. Industry analysts believed that electricity use in the

region for aluminum smelters would remain low in the 

coming years.11
State of the Markets Report • June 2005 103

Annual net revenues in 2004 from energy for gas-fired

technologies were below the five-year average for the

third consecutive year, in part because of relatively large net

revenues in 2000 and 2001. Annual net revenues from energy

for a combined cycle increased 8% from 2003. Revenues from

energy for a combustion turbine declined 73% from 2003. 

We estimate that new gas-fired combustion turbine plants in

the Northwest require $62.67/kW-yr, and gas-fired combined

cycle plants require $85.53/kW-yr, to meet debt and equity

requirements. The five-year average net revenue estimates for

both gas-fired combined cycle and combustion turbine plants

exceeded these levels only because of the exceptionally highpriced periods during 2000 and 2001. In 2002, 2003, and 2004,

estimated net revenue for gas-fired combined cycle and combustion turbine plants in the Northwest were below these

thresholds. 

Northwest Electric Market Profile

0.00

50.00

100.00

150.00

200.00

250.00

300.00

350.00

400.00

450.00

500.00

2000 2001 2002 2003 2004

$ / kW-year

CC Net Revenue

CT Net Revenue

CC New Entry Costs

CT New Entry Costs

COB Net Revenue from Energy

Source: Derived fromPlatts day-ahead gas prices for Malin and Platts day-ahead

power prices for COB. See “Analytic Note on Net Revenue Calculations” in the Other

Material section for details.

NET REVENUE
104 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Northwest Electric Market Profile

1. Prices are Dow Jones firm day-ahead on-peak prices for the locations identified.

2. Platts Megawatt Daily, IntercontinentalExchange (ICE) and Dow

Jones prices are firm day-ahead on-peak for the Mid-Columbia Hub. 

3. Data are from WECC, “Summary of Estimated Loads and

Resources,” as of July 2004 and May 2005. WECC data reflects certain hydroelectric facility derates and limitations as reported by

Northwest control area operators. The Northwest is a winter peaking area, generally energy-constrained and not capacity-constrained.

4. Platts Megawatt Daily, ICE and Dow Jones prices are for firm dayahead on-peak delivery to the California/Oregon Border (COB). 

5. ICE on-peak forward and swap prices and volumes are for MidColumbia and include monthly, dual monthly, quarterly, and calendar year contracts traded for 2004. New York Mercantile Exchange

(Nymex) ClearPort on-peak swaps volumes are for Mid-Columbia

and are traded by month. 

6. Data from Platts PowerDat, RDI Modeled Production Costs dataset

for calendar year 2003 reflecting self-reporting from all utility and

nonutility electric power generating facilities with nameplate capacity of 50 MW or more.

7. Data from Energy Information Administration (EIA) Form 860, Platts

NewGen and Platts PowerDat. All generation is summer capacity

unless otherwise indicated.

Disclaimer: This report contains analyses, presentations and 

conclusions that may be based on or derived from the data sources

cited, but do not necessarily reflect the positions or recommendations

of the data providers. 

Source notes

1 BPA was initially formed to sell power from federal hydropower

generation in the Northwest. Subsequently, BPA has also

signed agreements to sell power from certain nonfederal power

plants in the Northwest such as Energy Northwest’s nuclear

plant, Columbia Generating Station. BPA sells most of its power

at cost-based rates to Northwest public utilities and direct service industries such as aluminum smelters. When surplus power

is available, BPA also sells power to the western market that it

has in excess of its existing firm contractual commitments. This

surplus power is sold at market prices.

http://www.bpa.gov/corporate/about_BPA/facts/index.cfm,

and Bonneville Power Administration News, September 23,

2004.

2 Bonneville Power Administration 2004 Annual Report, 27.

3 From October 2000 through September 2001 the Northwest

experienced below-normal precipitation and streamflows and,

hence, below-normal hydroelectric production (2001 streamflow, as measured at The Dalles Dam, was 58 million acre-feet,

which was 56% of the 70-year average of 104 million acre-feet).

The Northwest exported electrical energy to the combined

regions of California and the Southwest in ten months of 2001.

Northwest Power Pool data downloaded from

http://www.nwpp.org/pdf/historical_data.pdf, on April 12,

2005.

4 Oregon Public Utilities Commission, Order Number 05-114, 24.

http://www.puc.state.or.us/orders/2005ords/05-114.pdf.

5 BPA does not own generation, but markets the output of the

federal hydropower facilities in the Northwest and that of a few

nonfederal power plants.

6 NWPCC (http://www.nwcouncil.org/energy/powerplan/draftplan/(09)%20Transmission%20(PP).pdf).

7 Grid West http://www.rtowest.com/Doc/

TSLG_RRGUpdateReport_Oct272004.pdf.

8 Capacity Additions and Retirements are for calendar year 2004,

based on Platts and EIA net summer capacity estimates and FERC

staff research. They may differ from the Summer Generating

Capacity in the Supply Demand Statistics table. Summer

Generating Capacity may be projected for the summer peak, may

omit some calendar year additions, and may reflect actual

demonstrated capacity and deratings.

9 Platts PowerDAT, NEWGen as of March 1, 2005, EIA Form 860,

FERC Staff Research. Data are summer capacity unless otherwise indicated. 

10 WECC 10-Year Coordinated Plan Summary (September 2004),

NERC Energy Supply and Demand database, FERC analysis.

Data are for new transmission lines 230kV and above unless

otherwise indicated. 

11 See “BPA Comments on the Council’s draft Fifth Power Plan”;

“The Demand Wild Card: Pacific Northwest Aluminum,”

Cambridge Research Associates, July 2003, 1–6; “Fifth Power

Plan: Pre-publication draft,” Northwest Power and Conservation

Council, A–15, A-23–A-27, 1–3. Northwest Aluminum Industry

Study Group, January 26, 2001; OMOI conversation with BPA,

April 7, 2005; At the London Metals Exchange, cash market

prices for aluminum started in 2004 at $1,460 per ton and

ended the year at $1,721 per ton (Bloomberg, March 23, 2005);

“2003 Pacific Northwest Loads and Resources Study: The White

Book,” BPA, July 15, 2004, 48. 

Endnotes
By January 1, 2005, the PJM Interconnection LLC (PJM)

electric market stretched from the Atlantic Coast to the

Midwest and included all or part of the high-voltage electric

system in 12 states and the District of Columbia.1 Thus, PJM

includes all or portions of the North American Electric

Reliability Council (NERC) regions of the Mid-Atlantic Area

Council (MAAC), the East Central Area Reliability

Coordination Agreement (ECAR), and the Mid-America

Interconnected Network (MAIN). In 1998, PJM, as independent system operator (ISO), began centrally dispatching the

region’s power grid and operating a spot energy market. The

energy market is now an RTO with a two-settlement market

(day-ahead and real-time) using locational marginal pricing

(LMP). 

PJM also operates a regional capacity market, a financial transmission rights market, and markets for some ancillary services.

Market participants also actively trade electricity bilaterally

through brokers and the IntercontinentalExchange (ICE), often

using the PJM Western Hub as the pricing point. Average 2004

peak prices for the PJM Western Hub increased 5%–6% from

2003.

PJM Electric Market Profile

State of the Markets Report • June 2005 105

Existing PJM January 2004

Integrated Areas January 2004 - January 2005

PA

North 

Illinois Hub

$42.15 NY

KY

MI

IN

IL

VA

WV

NJ

DE

MD

OH

TN

Western Hub

$50.63

NJ Hub

$59.47

• Control Area Integration.

The integration of the

Commonwealth Edison

(ComEd), American Electric

Power (AEP), and Dayton

Light and Power control areas

in 2004 increased PJM’s peak

load approximately 70%. 

PJM also added the Duquesne

Light Co.’s area on January 1,

2005.

• Joint Operating Agreement.

PJM and the Midwest

Independent Transmission

System Operator (MISO) 

initiated a Joint Operating

Agreement (JOA) on

December 31, 2003, to 

formalize the seams arrangements between the two

regional transmission organizations (RTOs.) For 2004, the

JOA set procedures for the

market (PJM) to nonmarket

(MISO) interface. With MISO’s

central dispatch market startup in 2005, the JOA will foster

an efficient procedure for

management of congestion

through re-dispatch based on

market prices. PJM and MISO

formulated the JOA in partial

compliance with the

Commission’s directive to

design a seamless market

between the two RTOs.2

• Moderate weather kept PJM

from setting new peaks and 

moderated prices during the

past two summers. However,

a combination of cold weather

and high natural gas prices

caused price spikes of limited

duration in winter 2003–04.

Supply Demand Statistics

2003 2004 Exp. 2005

Summer Generating Capacity MW 140,498 140,855 143,620

Summer Peak Demand MW 112,355 105,541 115,166

Summer Reserves MW 28,143 35,314 28,454

Summer Reserve Margin 25% 33.5% 24.7%

Annual Energy Gwh 598,452 605,432

PJM Western Hub Prices

2003 2004 5-Year

Platts $48.49 $51.10 $40.77

ICE $48.39 $51.10 NA 

RTO $47.71 $50.63 $41.40

Source: Derived from PJM, ICE and Platts data. See source note 2. Source: Derived from PJM, Platts and Energy Information Administration (EIA) data.

See source note 3.

Source: Derived from PJM data. See source note 1.

2004 Average Hub Prices for On-Peak Hours ($ per MWh)

Focal Points for 2004
106 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Day-ahead, peak bilateral prices from Platts and ICE are

illustrated as well as RTO day-ahead and real-time locational

marginal prices. Prices in PJM were higher in 2004 than in

the previous year largely due to higher fuel costs. However,

as a result of the integration of areas with lower cost generation and moderate temperatures, average spot prices in PJM

actually declined after adjustment for fuel costs.3

The integration during 2004 of major service areas into PJM

markedly increased the load served. Before the ComEd integration, the average daily peak load was 41,753 MW. After the

ComEd integration, but before the AEP and Dayton integrations, the average daily peak load was 58,661 MW. From the

time of the AEP and Dayton integrations to the end of the year,

the average daily peak load was 70,595 MW.

Platts volume reports of bilateral trading for the PJM Western

Hub peaked on July 23 at 4,650 MW and averaged 1,996 MW.

ICE volume peaked on May 5 at 84,000 MW and averaged

28,314 MW. In reports of bilateral trading for Northern Illinois,

Platts volume peaked on February 9 at 3,575 MW and averaged

913 MW; ICE volume peaked on November 11 at 31,200 MW

and averaged 7,450 MW.

The differences are also shown between the average peak-hour,

day-ahead price and average peak-hour, real-time price. These

differentials center around zero with a small bias toward a higher day-ahead price in peak hours.

PJM Electric Market Profile

SPOT MARKETS: PRICES AND VOLUMES

FINANCIAL MARKETS: PRICES AND VOLUMES

Daily Average of On-Peak Prices

$0

$20

$40

$60

$80

$100

$120

$140

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

$/MWh

Platts PJM West

RTO Western Hub

Daily Average RT vs. DA On-Peak Prices

-$80

-$60

-$40

-$20

$0

$20

$40

$60

$80

Jan

FebMar

Apr

May

Jun

Jul

AugSep

Oct

NovDec

$/MWh

RTO Western Hub (RT - DA)

Source: Derived from PJM and Platts data. See source note 4. Source: Derived from PJM data. See source note 5.

Swaps Prices from Trade Date Forward and Swaps Volume

$0

$20

$40

$60

$80

$100

$120

$140

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

$/MWh

12/15/2003

03/15/2004

06/15/2004

09/15/2004

0

10,000

20,000

30,000

40,000

50,000

60,000

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

MWh (thousands)

ICE PJM Forward Volume

ICE PJM Swaps Volume

ClearPort PJM Futures Volume

Source: Derived from ICE data. See source note 6. Source: Derived from ICE and Nymex data. See source note 6.
PJM requires that all load-serving entities in PJM maintain contracted or owned capacity equal to their load, plus a specified

reserve (15% of forecasted peak in 2004). They may purchase

capacity bilaterally, own the capacity, or transact through the

PJM capacity market. With the integration of the northern

Illinois control area, PJM started a second, parallel capacity auction for the northern Illinois control area. All other areas use

the original capacity auction process. Capacity for the northern

Illinois control area is procured in a separate auction with different rules and capacity requirements. A single PJM-wide

process took effect June 1, 2005, when differences between PJM

capacity requirements and MAIN capacity requirements were

reconciled. 

For PJM, financial markets consist of both physical forward and

financial swaps. Market participants use many platforms for their

financial transactions. Data are available for ICE and Nymex

only.

Financial trading increased on both the Nymex ClearPort and

ICE trading platforms. Trading of PJM financial products on

Nymex ClearPort for the fourth quarter was 30% higher than for

the first quarter. Trading of financial products on ICE for the

fourth quarter was 29 times higher than the first quarter. Trading

of ICE PJM physical volumes outweighed financial volumes until

July. By the fourth quarter, financial trading volumes on ICE outweighed the physical volumes by more than six-fold.

The increase in trading of PJM financial products is consistent

with the general trend in electricity trading as more nontraditional electricity trading entities (hedge funds and banks) have

become active in financial markets, as industry credit has

improved, and as platforms like ICE and Nymex have begun to

offer clearing of trades. Trading of PJM financial products on ICE

and Nymex ClearPort outweighed trading for other regions and

hubs significantly.

State of the Markets Report • June 2005 107

CAPACITY AUCTIONS

PJM Electric Market Profile

PJM Capacity Auction Prices

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

$/kW-mo

Monthly/Multi-Monthly

Daily

Weighted Average

PJM Capacity Auction Volume

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

Jan

FebMar

Apr

May

Jun

Jul

AugSep

Oct

Nov

Dec

MW

Daily

Monthly/Multi-Monthly

Source: FERC/OMOI analysis of PJM data. See source note 7. Source: Derived from PJM data. See source note 7.
108 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

PJM Electric Market Profile

PJM mitigates generator offers when units are in a

transmission-constrained area and are needed for reliability. Units in PJM Mid-Atlantic whose construction

started between July 9, 1996 and September 30, 2003

are exempted. Also, if the relevant constraint is either

the eastern or western interface, mitigation is not

imposed. When a unit is mitigated, its offer is generally restricted to its variable cost (on file with PJM), plus

10%. Some frequently mitigated units are allowed an

adder on top of the normal mitigated offer through a

negotiated option.

The mitigation experience for 2004 was slightly higher than the previous year. The share of total unit run

hours under mitigation was 1.3% in 2004 (1.1% in

2003). The trend had been declining mitigation since

2001, when 2.8% of the unit run hours were under

mitigation.

Northern Illinois Capacity Auction Prices

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

NovDec

$/kW-mo

Monthly/Multi-Monthly

Northern Illinois Capacity Auction Volume

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

Jan

FebMar

Apr

May

Jun

Jul

AugSep

Oct

NovDec

MW

Monthly/Multi-Monthly

Source: Derived from PJM data. See source note 8. Source: Derived from PJM data. See source note 8.

The PJM capacity markets consist of monthly and multi-monthly

auctions and also a daily auction, each auctioning unforced capacity (UCAP), that is, generators’ demonstrated capacity adjusted

for forced outage history. Capacity can be purchased in any of

these auctions, with monthly and multi-monthly auctions occurring at frequent intervals through PJM’s website. Load-serving

entities that do not procure enough resources to meet their capacity obligations must pay a deficiency payment to PJM.

Capacity prices were highest in the summer months, particularly

June. A drop in capacity imports, adjustments to forced outage

rates, and generator retirements decreased UCAP supply by 1,400

MW. The PJM market monitor noted a change in capacity bidding patterns: Supply offers were higher than in previous months,

and load purchased more capacity in the daily auction.4

The northern Illinois capacity markets consist of monthly and

multi-monthly auctions, auctioning installed capacity (ICAP).

Capacity can be purchased in monthly and multi-monthly auctions, which PJM conducts at frequent intervals. Load-serving

entities that do not procure enough resources to meet their capacity obligation must make deficiency payments.

Capacity in the northern Illinois control area was highly concentrated: nearly two-thirds was owned or controlled by one entity.5

Auction volumes fell in October after a change in seasonal obligations on October 1.

Offer Mitigation
State of the Markets Report • June 2005 109

PJM Electric Market Profile

Capacity and Generation by Fuel and Prime Mover

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Capacity Net Generation 

Share of Regional Total (%)

OIL CT

GAS/OIL CT

GAS CT

OIL ST

GAS/OIL ST

GAS/OIL CC

GAS ST

GAS CC

COAL ST

NUCLEAR

WIND

HYDRO

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Capacity Net Generation 

Share of Regions Total (%)

PEPCO Holdings, Inc.

Mirant Corp.

Constellation Energy

Group, Inc.

Reliant Energy, Inc.

PPL Corp.

Allegheny Energy, Inc.

Edison International

Public Service Enterprise

Group, Inc.

Exelon Corp.

American Electric Power

Co., Inc

Source: Derived from Platts data. See source note 9.

Source: Derived from Platts data. See source note 9.

In 2003, hydroelectricity, wind, nuclear energy, and coal constituted 70% of the total PJM capacity and provided almost all net

generation. By comparison, gas-fired capacity was 18% of the

total and contributed 2% of annual net generation in 2003;

dual-fuel (gas/oil) generators constituted 6% of capacity and

contributed 1% of annual net generation. 

2003 RESOURCE MIX

2003 MARKET CONCENTRATION

The top 10 owners provided 77% of capacity and 84% of generation in PJM in 2003. Seven of the top 10 generation owners in

PJM were regional utilities or their affiliates. Three of the top

10 providers were independent power producers or utility affiliates that built or acquired generating assets outside of their traditional service territories. 

The top 10 major utilities supported 91% of peak load and 93%

of total retail sales in the region. Many of the largest suppliers

of retail load in PJM were also the largest owners of generation

and were able to cover much of their load through self-supply.

Capacity and Generation of Top 10 Companies
0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

PJM Prior to May

1

With ComEd

Integration-May 1

With AEP/Dayton

Integration-Oct.1

With Duquesne

Integration-Jan.

1, 2005

Megawatts

Peak Load 

Generating

Capacity

110 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

PJM Electric Market Profile

After years with practically no generation retirements in

the PJM Mid-Atlantic region, late 2003 and 2004 saw an

upsurge in notifications to PJM from owners that

planned to retire units. Owners removed more than

2,000 MW of generation from service in 2004. Before

this activity, PJM did not have a formal policy for coordinating retirements between the generator owners and

the RTO. PJM placed an informal policy in effect until

the Commission approved the elements of what is now

PJM’s formal retirement policy.6 The current policy

requires generators to notify PJM of planned retirements 90 days before they take effect and requires PJM

to respond with an estimate of effects on reliability

within 30 days of the notification. If the retirement does

pose a reliability risk, the policy provides for a mechanism to reimburse the owner for the cost expended to

continue operation. PJM received 58 requests to deactivate units during 2004.

Expansion

Source: PJM press releases.

PJM EXPANSION

In 2004, ComEd, Dayton, and AEP control areas integrated into

the area for which PJM controls the transmission service and

operates a centralized spot energy market. PJM also added the

Duquesne Light Company area on January 1, 2005. 

ComEd joined the RTO on May 1, 2004. Because ComEd did not

have a direct electrical connection to PJM at the time, PJM

devised a temporary 500 MW pathway of transmission reservations through AEP to connect the two areas. From May to

October, PJM centrally dispatched the ComEd control area, along

with the rest of PJM, but the limited capacity of the pathway often

prevented full economic use of capacity in northern Illinois. On

October 1, AEP and Dayton joined PJM and became part of PJM’s

central dispatch and spot market. With AEP in PJM, the pathway

was no longer necessary, and transactions between the far-western reaches of PJM and the Mid-Atlantic portion ran smoother.

For each integration phase, PJM and the participants conducted

two, full-scale market trials. PJM also held numerous simulation

and training exercises to prepare its own operations and to help

participants learn to take part in the new markets. PJM also had

to allocate Financial Transmission Rights for each new area and

prepare its Open Access Same Time Information System (OASIS)

to provide transmission service in the expanded configurations.

Operation of an LMP system in these new areas has presented

challenges for PJM and its neighbors, particularly MISO, in dealing with inadvertent energy movement across new borders. As

discussed above, PJM and MISO formulated a joint operating

agreement for solutions to these seams situations, and the integrations have proceeded without major problems. PJM added the

Dominion-Virginia Power service territory on May 1, 2005.

Existing PJM January 2004

ComEd added May 2004 

Dayton added October 2004 

AEP added October 2004 

Duquesne added January 2005 

PA

NY

KY

MI

IN

IL

VA

WV

NJ MD

OH

TN

Recent Increase in Generation Retirements

Source: PJM press releases.
State of the Markets Report • June 2005 111

PJM Electric Market Profile

Annual net revenue from energy for gas-fired technologies in

2004 was below the five-year average for the second consecutive

year. For a combined cycle, revenue from energy increased

1.1% from 2003 but was still 26.7% below the five-year average.

For a combustion turbine, revenue from energy reached a fiveyear low, declining from $9.76/kW-year in 2000 to $0.05/kWyear in 2004.

FERC estimated cumulative annual net revenue for sale of energy at the PJM western trading hub. 

Estimates of the cost of new entry in PJM vary. For example,

PJM estimates were higher than the EIA-based estimates above:

$93.50/kW-year for a new combined cycle and $72.20/kW-year

for a new combustion turbine.7 In addition, the EIA-based cost

estimates do not provide a detailed picture of intrastate cost

divergence. According to a Strategic Energy Services Inc.

report, new-entry costs for a combustion turbine (CT) in New

Jersey are estimated at $72.21/KW-year, slightly lower than for

a CT in Maryland or Illinois at $74.12/kW-year and

$73.84/kW-year, respectively.8

Estimated PJM 2004 net energy revenues fell below all of these

thresholds. The addition of estimated net revenue from capacity made little difference. Without significant net revenue from

energy, capacity, and ancillary services, market-based investment was not signaled.

0.00

10.00

20.00

30.00

40.00

50.00

60.00

70.00

80.00

90.00

2000 2001 2002 2003 2004

$ / kW-year

CC Net Revenue

CT Net Revenue

CC New Entry Costs

CT New Entry Costs

PJM Western Hub Net Revenue from Energy

Source: Derived from Platts and EIA data. See source note 10.

NET REVENUE

Net Energy Net Capacity Total Revenues 

$/KW - yr $/KW - yr $/KW - yr

CC $48.49 $51.10 $40.77

CT $48.39 $51.10 NA 

Source: Derived from Platts and EIA data. See “Analytic Note on Net Revenue

Calculations” in the Other Material section for details. See also source note 10.

Regional Net Revenue from Energy and Capacity

Before integration, PJM was a net importer of energy. After

integration of the northern Illinois control area and continuing

with the integration of AEP and Dayton, PJM became a net

exporter. PJM was a net importer on five days after May 1 (June

16, November 21, December 5, December 6, and December 7).

Before ComEd integration on May 1, average net imports were

2,539 MW. May through September average net exports were

1,529 MW. After the AEP and Dayton integrations on October

1, average net exports were 1,811 MW.

Average Daily Net Interchange

-5,000

-4,000

-3,000

-2,000

-1,000

0

1,000

2,000

3,000

4,000

5,000

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

NovDec

Net Exports (MWh)

Source: Derived from PJM data. See source note 11.

REGIONAL EXPORTS AND IMPORTS
112 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

PJM Electric Market Profile

1 This section includes all PJM regions existing or integrated

through January 1, 2005.

2 Commission Order Providing Guidance on Midwest ISO and PJM

Structure, 100 FERC 61,137 (2002), paragraph 48.

3 PJM, 2004 State of the Market (PJM SOM), (March 8, 2005), 48.

4 PJM SOM, 164–166.

5 PJM SOM, 170.

6 PJM Open Access Transmission Tariff, Section V. 

7 PJM, 2004 State of the Market (March 8, 2005). Cost of new entry

levelized over the 20-year life of a project.

8 “Reconciliation of Initial to Final Revenue Requirements, Final

Revenue Requirements Region,” Ray Pasteris, President,

Strategic Energy Services Inc., February 4, 2005. See

http://www.pjm.com/committees/workinggroups/pjmramwg/

downloads/20050209-cone-ct-reconciliation.pdf.

9 Platts PowerDAT, NEWGen as of March 1, 2005. EIA Form 860,

FERC Staff Research, PJM Market Monitor Unit. Data are for summer capacity, unless otherwise indicated. Capacity Additions and

Retirements are for calendar year 2004, based on Platts and EIA

net summer capacity estimates and FERC staff research. They

may differ from the Summer Generating Capacity in the Supply

Demand Statistics table. Summer Generating Capacity may be

projected for the summer peak, may omit some calendar year

additions, and may reflect actual demonstrated capacity and deratings.

10 NERC ES&D Database 2004. Updates from NERC as of April 19,

2005. Data are for new transmission lines 230 kV and above,

unless otherwise indicated.

Endnotes

In 2004, 4,202 MW of new generation and five major transmission projects were completed in PJM. During the year, 78 MW

of generation was mothballed and 2,742 MW was retired.9

Generation Additions. In the PJM region, 10 generation projects came on line. All, except for one 10-MW plant, are fueled

by natural gas. The five largest plants total 3,800 MW and are

independent power producer projects, including the PSEG

Lawrenceburg Energy Facility (1,062 MW at a cost of $600 million) and the Fairless Energy Center (1,150 MW). Capacity

additions in 2004 were lower than in the two previous years. In

2004, 2,740 MW of generation were retired, most of which were

owned by Reliant, Edison Mission Energy (EME), and PSEG

Power. This total included the Collins plant, owned and retired

by EME.

Transmission Additions. Five major transmission projects were

completed in PJM, totaling 6.4 miles.10 Three of the new projects

were completed by AEP in the ECAR region. 

Capacity Additions

-4000

-2000

0

2000

4000

6000

8000

10000

2002 2003 2004

MW

PJM Additions

PJM Retirements

PJM Mothballed

GENERATION AND TRANSMISSION ADDITIONS AND RETIREMENTS

Source: Derived from PJM, EIA and Platts data. See source note 12.
State of the Markets Report • June 2005 113

PJM Electric Market Profile

1. Prices are PJM’s day-ahead locational marginal prices for the

hubs identified. Data located at http://www.pjm.com/markets/

energy-market/day-ahead.html. On-peak hours are from 7:00

a.m. to 11:00 p.m. Monday through Friday excluding NERC holidays. Northern Illinois Hub price series began May 1, 2004.

2. Platts Megawatt Daily and IntercontinentalExchange (ICE) prices

are day-ahead on-peak for “PJM West.” PJM prices are dayahead locational marginal prices for the Western Hub, data

located at http://www.pjm.com/markets/ energy-market/dayahead.html. 

3. Data from PJM’s 2005 Load Forecast Report, February 2005;

Platts NewGen, Platts PowerDat, and EIA. Summer generating

capacity is that capacity available each summer at summer rating. Summer peak demand in 2003 did not reflect diversity

between Mid-Atlantic and West peaks. 

4. Platts Megawatt Daily prices are day-ahead on-peak for the

“PJM West.” PJM prices are day-ahead locational marginal

prices for the internal Hub, data located at

http://www.pjm.com/markets/energy-market/day-ahead.html.

5. PJM prices include real-time and day-ahead locational marginal

prices for the internal Hub. PJM real-time price data located at

http://www.pjm.com/markets/jsp/lmp.jsp. PJM day-ahead

price data located at http://www.pjm.com/markets/energymarket/day-ahead.html. 

6. ICE on-peak forward and swap prices and volumes are for PJM’s

Western Hub and include monthly, dual monthly, quarterly, and

calendar year contracts traded for 2004. New York Mercantile

Exchange (Nymex) ClearPort on-peak swaps volumes are for

PJM’s Western Hub traded by month. 

7. PJM capacity price and volume information is located at

http://www.pjm.com/pub/capacity_credit_market/ downloads/daily.csv for daily and http://www.pjm.com/pub/

capacity_credit_market/downloads/stat.csv for longer terms.

8. PJM capacity price and volume information for Northern Illinois

is located at ftp://ftp.pjm.com/pub/capacity_credit_market/

results/ nica/ccmmonthly-nica.csv.

9. Data from Platts PowerDat, RDI Modeled Production Costs

dataset for calendar year 2003 reflecting self-reporting from all

utility and non-utility electric power generating facilities with

nameplate capacity of 50 MW or more.

10. The analysis is based on Platts Megawatt Daily’s day-ahead onpeak electric prices for the Western Hub and from Platts Gas

Daily’s day ahead natural gas prices from Transco Zone 6 (nonNew York). The figure does not include revenue from capacity or

ancillary services. For a detailed discussion of the calculation

method, see “Analytic Note on Net Revenue Calculations” in the

Other Material section of the Report.

11. Average hourly net interchange data are from PJM real-time tie

schedules and can be found at

http://www.pjm.com/markets/jsp/nts.jsp. 

12. Data from PJM, Energy Information Administration (EIA) Form

860, Platts NewGen and Platts PowerDat. All generation is summer capacity unless otherwise indicated.

Disclaimer: This report contains analyses, presentations, and conclusions that may be based on or derived from the data sources cited, but

do not necessarily reflect the positions or recommendations of the

data providers. 

Source notes
114 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

PJM Electric Market Profile
The Southeast electric market is composed of two regions designated by the North American Electric Reliability Council

(NERC): the Florida Reliability Coordinating Council (FRCC) of

peninsular Florida, and the Southeastern Electric Reliability

Council (SERC), which includes the Southern, Entergy,

Tennessee Valley Authority (TVA), and VACAR (VirginiaCarolinas) subregions. Eleven control areas dispatch in

coordination with FRCC’s Reliability Coordinator and 22

control areas dispatch in coordination with SERC’s

Reliability Coordinator. Physical and financial electricity

products are traded using Entergy, Southern, TVA, VACAR, and

Florida price points. Volumes for these products remain low,

especially in Florida where merchant power plant development is

restricted by a state statute. In addition, there is trading on

IntercontinentalExchange (ICE) for the Entergy Hub, Southern

and TVA. Average 2004 peak prices for the Entergy Hub increased

about 10% over 2003. Average prices were similar in Entergy,

Southern, TVA, and VACAR, and slightly higher in Florida. 

The SERC region had a large pool of interconnected generation capacity that was designated “noncommitted.” The

deliverability of output from these facilities is not assured

because they lacked firm transmission capacity or agreements to serve load; yet they often sold power into the spot

market. These plants are primarily located in the Entergy

and Southern subregions and totaled 45,579 MW. They were

not included in the EIA-411 SERC regional capacity of

180,038 MW, or in the reserve margin of 16.6%. If included,

capacity would have increased to 225,617 MW with a reserve

margin of 42.4%.1

Southeast Electric Market Profile

State of the Markets Report • June 2005 115

Entergy

Southern

TVA

VACAR

SERC Subregions FRCC

FRCC

TVA

$44.23 NC

FL

TX

Florida

$58.31

Southern

$48.67

Entergy

$45.76

VACAR

$48.27

SC

GA

MS AL

LA

AR

MO

IL IN OH

IL WV

VA

TN

• Hurricanes battered Florida

during summer 2004. Four

major storms caused widespread damage and loss of

service to customers. Hurricane

Frances disrupted operations

affecting four million end-users.

The repeated storms strained

utility recovery operations

because of widespread damage

to the local distribution systems

from downed wires. Despite

this, there was only minor damage to generation and transmission assets. Nuclear and fossil

power plants were shut down

as a precaution, and there were

fuel disruptions because of

damage to the gas system, wet

coal stockpiles, and some fuel

oil delivery interruptions. In

spite of such problems, power

prices remained stable as supply

and demand fell simultaneously

in roughly equal proportions.

• Southeast utilities organizing

the SeTrans RTO suspended a

2-year effort in December 2003

to create a regional transmission organization. They stated

that “the retail commissions in

the region have expressed 

significant concerns about the

role of an RTO and its effects on

matters subject to their jurisdiction, including concerns about

native load protection and cost

impacts.” The SeTrans members were City of Dalton (Ga.)

Utilities, City of Tallahassee

(Fla.), Cleco Corp. Entergy

Services, Georgia Transmission

Corp., Jacksonville (Fla.) Electric

Authority, the Municipal Electric

Authority of Georgia, Sam

Rayburn Electric Cooperative,

Santee Cooper, Southern Co.,

and South Mississippi Electric

Power Association.

• New investment in the SERC

region’s transmission system

totaled $1.13 billion in 2004.2

Based on a survey of the capital

investment plans of the regional utilities, this level is expected

to remain consistent each year

through 2010.

2003 2004 Exp. 2005

Summer Generating Capacity MW 214,207 218,438 223,029

Summer Peak Demand MW 193,585 200,666 205,387

Summer Reserves MW 20,622 17,772 17,642

Summer Reserve Margin 11% 9% 9%

Annual Load GWh 1,045,985 1,088,336 1,114,169

Entergy Prices

2003 2004 5-Year

Platts $41.47 $45.76 $41.10

ICE $41.45 $45.86 NA 

Source: Derived from Platts and IntercontinentalExchange (ICE) data. All prices are in

nominal dollars. See source note 2.

Source: Derived from NERC and SERC data. See source note 3.

2004 Average Regional Prices for On-Peak Hours ($ per MWh)

Supply Demand Statistics

Source: Derived from Platts data. See source note 1.

Focal Points for 2004
In the Southeast, financial markets consist of physical forwards.

ICE clears physical trading into Entergy, Southern, and TVA.

Entergy is the most actively traded Southeastern product on ICE. 

For 2004, Entergy trading was highest for the third quarter. At the

end of the year, trading of the fourth quarter products was more

than 60% higher than for the first quarter.

116 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Southern and TVA prices peaked in the mid-$60s per MWh,

Southern on December 15 and TVA on June 9. Florida and

VACAR peaked in the lower $70s, Florida on various dates in June

and VACAR on January 7. Entergy peaked in the high $50s on

December 15. All prices in the Southeast were the lowest on

January 2; Florida was in the mid-$30s, whereas all others areas

were in the mid to lower $20s.

In bilateral trading reporting by Platts, Entergy volumes averaged

1,000 MW, peaking at 3,000 MW on May 24; Florida volumes

averaged 50 MW, peaking at 50 MW on August 19; Southern volumes averaged 721 MW, peaking at 1,800 MW on August 19; TVA

volumes averaged 438 MW, peaking at 600 MW for August 4; and

VACAR volumes were not reported by Platts for 2004.

Prices in the Southeast were stable in 2004, which is typical for the

region. Two factors contributed to this: first, there was a general

level of generation overbuild, minimizing supply constraints.

Second, the generation mix in the region has a high proportion of

coal and nuclear plants, which have lower fuel price volatility

than gas-fired units.

The pricing basis differential between the adjacent Southern

SERC subregion and the FRCC region of peninsular Florida averaged $8.39 in 2004. The regions’ generation plant mix differs—

86% of the output is from coal and nuclear in Southern, and 48%

in the FRCC.3 Limited transmission interconnection between 

the regions tends to prevent the local prices in the areas from 

converging.

Southeast Electric Market Profile

SPOT MARKETS: PRICES AND VOLUMES

FINANCIAL MARKETS: PRICES AND VOLUMES

Daily Average of On-Peak Prices

$0

$20

$40

$60

$80

$100

$120

$140

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

$/MWh

Platts Entergy Platts Florida-in-State

Platts Southern Platts TVA

Platts VACAR

Comparison of On-Peak Prices between Platts and ICE

$0

$20

$40

$60

$80

$100

$120

$140

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

$/MWh

Platts Entergy

ICE Entergy

Source: Derived from Platts data. See source note 4. Source: Derived from Platts and ICE data. See source note 5.

Entergy Forward Prices from Trade Date Southeast Forward Volume

$0

$20

$40

$60

$80

$100

$120

$140

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

$/MWh

12/15/2003

03/15/2004

06/15/2004

09/15/2004

0

200

400

600

800

1,000

1,200

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

MWh (thousands)

ICE Entergy

ICE Southern

ICE TVA

Source: Derived from ICE data. See source note 6. Source: Derived from ICE data. See source note 6.
State of the Markets Report • June 2005 117

Southeast Electric Market Profile

Capacity and Generation by Fuel and Prime Mover

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Capacity Net Generation

Share of Regional Total (%)

OIL CT

GAS/OIL CT

GAS CT

OIL ST

GAS/OIL ST

GAS/OIL CC

GAS ST

GAS CC

COAL ST

NUCLEAR

WIND

HYDRO

2003 RESOURCE MIX

In 2003, nuclear and coal totaled 48% of total Southeast capacity and provided 78% of net generation. The region depends on

natural gas for intermediate and peak loads with gas-fired combined cycle capacity that provided 16% of the capacity in 2003

and contributed 10% of annual net generation. 

Within the Southeast, the resource mix varies between NERC

regions and subregions. The FRCC has a much greater utilization of gas and oil than the rest of the Southeast and is notable

as the only area where oil is significantly employed. Gas is the

marginal fuel in almost all hours in the FRCC. Within SERC,

the Southern subregion generates over 85% of electricity from

baseload coal and nuclear plants, yet still has gas as the marginal fuel more than 50% of the time. The Entergy subregion uses

gas to a much greater extent than the regional average; it is the

marginal fuel more than 70% of the time. The TVA subregion

has a significant amount of hydro capacity and output, and very

little dependence on gas. The VACAR subregion has the highest utilization of nuclear generation in the Southeast: 94% of its

output was from baseload coal and nuclear facilities.4 Source: Derived from Platts data. See source note 7.

2003 MARKET CONCENTRATION

The top 10 owners provided 72% of capacity and 77% of generation in the Southeast in 2003. All of the top 10 generation owners

in the Southeast are regional utilities, their affiliates, or large

municipals and cooperatives; the largest independent power producer in the region owns less than 2% of Southeast capacity. 

In 2004, capacity concentration remained virtually unchanged

from 2003; however, there were several large asset sales to financial firms. Duke Energy North America, Duke’s merchant generation company, sold a pool of 8 plants with 5,325 MW of capacity

to MatlinPaterson. Goldman Sachs purchased Cogentrix, with

3,300 MW of capacity, and other plants were purchased by AIG

and Bear Stearns. In total, these transactions represent approximately 4% of the region’s capacity.

The top 10 major utilities supported 88% of peak load and 60% of

total retail sales in the region. Many of the largest suppliers of

retail load in the Southeast are also the largest owners of generation and cover much of their load through self-supply. Tennessee

Valley Authority, a federal power authority, is the primary source

of generation and transmission services in the TVA subregion.

The Authority provides wholesale power to 158 municipal and

cooperative power distributors, and direct service to 62 large

industries and government installations. In the TVA area, the

Authority operates 80% of the generation capacity, which produced 92% of the subregion’s electrical output in 2003. The

Tennessee Valley Authority, Georgia Transmission Corp., and

Oglethorpe Power include sales-for-resale to municipal and cooperative power distributors in their peak load calculations, but

these values are not included in their retail sales figures. 0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Capacity Net Generation

Share of Regions Total %

Oglethorpe Power Corp.

SCANA Corp.

TECO Energy, Inc.

Dominion Resources, Inc.

FPL Group, Inc.

Progress Energy, Inc.

Entergy Corp.

Duke Energy Corp.

Tennessee Valley

Authority

Southern Co.

Capacity and Generation of Top 10 Companies

Source: Derived from Platts data. See source note 7.
Annual net energy revenue for gas-fired technologies in 2004

were below the five-year average for the third consecutive year.

Annual net energy revenue for a combined cycle increased 46%

from 2003. For a combustion turbine, energy revenue reached

a five-year low, declining from $14.86/kW-year in 2000 to

$0/kW-year in 2004.

We estimate that new gas-fired combustion turbine plants in

the Southeast require $59.35/kW-yr, and gas-fired combined

cycle plants require $80.75/kW-yr, to meet debt and equity

requirements. Southeast 2004 net energy revenue estimates are

well below this threshold, which suggests that market-based

investments in new generation were not attractive.

0.00

10.00

20.00

30.00

40.00

50.00

60.00

70.00

80.00

90.00

2000 2001 2002 2003 2004

$ / kW-year

CC Net Revenue

CT Net Revenue

CC New Entry Costs

CT New Entry Costs

Southern Net Revenue from Energy

118 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Southeast Electric Market Profile

Source: Derived from Platts day-ahead prices for Transco 85 and day-ahead power

prices for Southern. See “Analytic Note on Net Revenue Calculations” in the Other

Material section for details.

NET REVENUE

Southeast Merchant Generation Sector Struggles with Overcapacity

The SERC region experienced a dramatic wave of merchant generation construction from 1999 to 2003.

Almost all of the plants were gas-fired and in most

cases built without the surety of a specific customer or

a contractual sales agreement. Those not included as a

network resource or contracted to receive firm

point-to-point transmission service were designated

“noncommitted” by the regional grid coordinator and

were not included in the official EIA-411 Capacity calculations—even though these units often participate in

the spot market. When included in the overall regional supply calculations, the SERC had a capacity margin

that exceeded 40% in the summer of 2004.

A significant portion of these units remain idle or

underused several years after completion and their

financial outlook remains difficult. Several factors

have contributed to this: the demand for electricity

will take many years before it reaches the level of overbuild, these gas-fired plants cannot compete with the

large base of coal- and nuclear-fueled plants in the

region, and, in many cases, these facilities have had

problems accessing the transmission grid to sell their

output. 

At year-end 2004, almost 19,000 MW of new generation had signed or filed agreements to connect to the

SERC transmission system within the next 5 years. For

the entire Southeast, including both the SERC and

FRCC, the 2004 reserve margin was expected to

increase slightly from 2003 as supply additions outpaced demand growth.5
State of the Markets Report • June 2005 119

Southeast Electric Market Profile

In 1973, oil-fired plants constituted 55% of Florida’s generation

mix, and the foreign embargo that year caused oil prices to

quickly triple. The economics of oil plants were severely affected, and Florida’s utilities began to change their resource planning to reach a more balanced generation mix. By 2004, the

generation mix became more diversified, with coal units

accounting for 32% of output, “gas only” plants 29%, nuclear

16%, gas/oil dual fuel 13%, and “oil only” 9%. However, the

state’s utilities’ planning documents forecast a return to an

imbalanced mix, with natural gas-fired generation rising to

more than half the output over ten years. 

According to a study by the Florida Public Service

Commission’s (PSC) Economic Division, the state’s anticipated reliance on gas generation may force the utilities to again

reconsider their plans. Recent price increases and supply 

insecurity are sources of concern regarding gas, despite potential new capacity from proposed LNG facilities and increased

use of the Gulfstream pipeline. However, the Florida utilities

don’t have many easy alternatives and the study’s outlook on

other technologies highlights these concerns. Nuclear power

plants are not currently an option. Florida has few potential

renewable resources, with no significant capability for hydro or

wind generation, and prospects for immediate development of

landfill gas and solar installations also are substantially limited.

The question facing planners is: Do they continue down the

current path or is it time to change strategy again? 

The PSC report suggests coal as a possible answer, despite high

capital costs, emissions, and siting problems. An example of

one facility is the Orlando Utilities Commission’s announced

plans to build a 285 MW advanced coal gasification facility in

central Florida, in partnership with Southern Company,

which will cost $557 million. This facility is part of the U.S.

Department of Energy’s Clean Coal Power Initiative and is to

receive $235 million of federal funding. FPL is also considering

use of clean coal technology as it looks to meet its future 

development needs.9

GENERATION AND TRANSMISSION ADDITIONS AND RETIREMENTS

In 2004, 6,342 MW of generation were added (all gas-fired except

55 MW) and 2,546 MW were retired or mothballed. Thirteen

new transmission projects were connected in the Southeast

region.6

Generation Additions: In the Southeast/Florida region, 16 generation projects came on line with a total cost of about $3.5 billion. The largest was the 900 MW Tenaska Virginia Generation

Station, an independent power producer (IPP) plant in central

Virginia. Bayside and Osprey Energy Center are new plants in

Florida’s FRCC region (1,182 MW). The remaining plants are in

the SERC region. One of the few wind plants to come on line in

2004 was an 18 MW expansion of the Buffalo Mountain Wind

project in Tennessee. The level of capacity additions in 2004

declined from the previous two years. There were two generation

retirements in FRCC: the Gannon Plant, a 1,171 MW coal facility, and the Brandy Branch Generating Facility, a 317 MW natural

gas facility. In SERC, 172 MW of generation retired, 85 MW of

which was mobile cogeneration units. In SERC, 801 MW of

capacity was mothballed, of which 726 MW were at Reliant

Energy’s Choctaw County facility.7 

Transmission Additions: In 2004, 11 transmission projects were

completed and an additional 2 were scheduled to be completed in

the Southeast region, representing about 149 miles of new lines.

The longest was a 31-mile line west of Atlanta in the Georgia

Power territory (Yellow Dirt to Hickory Level). Florida Power

and Light had six projects, totaling 74 miles in length. Significant

areas of constraint remain at the SERC-FRCC interface, in the

greater Atlanta area and in southwest Louisiana. There are 16

projects totaling 248 miles scheduled to become active in SERC in

2005 and one 54-mile line in the FRCC.8

-5000

0

5000

10000

15000

20000

25000

2002 2003 2004

MW

FRCC Mothballed

SERC Mothballed

FRCC Retierments

SERC Retierments

FRCC Additions

SERC Additions

Capacity Additions

Source: Derived from EIA form 860 and Platts (summer capacity).

Florida Generation Resource Mix at a Crossroad
1 Southeastern Electric Reliability Council, Reliability Review

Committee, 2004 Report to the SERC Engineering Committee,

Information Summary, August 2004.

2 SERC, “SERC Generation & Transmission Development Survey

Results” presentation to the SERC Spring 2005 Joint Meeting,

March 10, 2005.

3 POWERdat, System Version 8.0.3, Release Date, September 22,

2004; Data Version 8.1.0804, January 2005.

4 CERA, “Company Structure Reflecting the Hybrid Industry

Landscape,” Figure 13.

5 SERC, Reliability Review Subcommittee, 2004 Report to the

SERC Engineering Committee, June 2004.

6 Capacity Additions and Retirements are for calendar year 2004,

based on Platts and EIA net summer capacity estimates and

FERC staff research. They may differ from the Summer

Generating Capacity in the Supply Demand Statistics table.

Summer Generating Capacity may be projected for the summer

peak, may omit some calendar year additions, and may reflect

actual demonstrated capacity and deratings.

7 Platts PowerDat, EIA Form 860, NEWGen as of March 24, 2005.

All generation data is in summer capacity unless otherwise indicated.

8 NERC Energy Supply and Demand database, SERC reliability

Review Subcommittee’s 2004 report to the SERC Engineering

Committee, and FERC analysis. All transmission data is for lines

230 kV and above unless otherwise indicated. 

9 Florida PSC Division of Economic Regulation, A Review of Florida

Electric Utility 2004 Ten-Year Site Plans, December 2004, Orlando

Utilities Commission website; PowerDat; FERC/OMOI analysis.

120 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Southeast Electric Market Profile

Source notes

1. Prices are from Platts Megawatt Daily for day-ahead on-peak

delivery at the identified pricing locations.

2. Platts Megawatt Daily and IntercontinentalExchange (ICE) prices

are for day-ahead on-peak delivery at the Entergy Hub. 

3. Data are from NERC’s 2004 ES&D Database and SERC,

“Reliability Review Subcommittee’s 2004 Report to the SERC

Engineering Committee” (June 2004). Summer generating

capacity, summer reserve and summer reserve margin values

do not include “Non-committed” generation resources in SERC.

Generation capacity excludes all derates of resources and

imports. 

4. Prices are from Platts Megawatt Daily for day-ahead on-peak

delivery at the identified pricing locations.

5. Platts Megawatt Daily and IntercontinentalExchange (ICE) prices

are for day-ahead on-peak delivery at the Entergy Hub. 

6. ICE on-peak forward and swap prices and volumes are for

Entergy, Southern and TVA as identified and include monthly,

dual monthly, quarterly, and calendar year contracts traded for

2004. Gaps in the December 15, 2004 forward prices are due to

insufficient trading volumes.

7. Data from Platts PowerDat, RDI Modeled Production Costs

dataset for calendar year 2003 reflecting self-reporting from all

utility and nonutility electric power generating facilities with

nameplate capacity of 50 MW or more.

8. Data from Platts PowerDat (System Version 8.0.3, release Date

September 22, 2004, data version 8.1.0804, January 2005) and

from CERA, “Company Structure Reflecting the Hybrid Industry

Landscape,” April 16, 2006, Figure 13.

Disclaimer: This report contains analyses, presentations and 

conclusions that may be based on or derived from the data

sources cited, but do not necessarily reflect the positions or 

recommendations of the data providers. 

Source: Derived from Platts and CERA. See source note 8.

Endnotes

Gas - Gas - Oil/Gas - Oil - CT - Hours of

Coal Nuclear Hydro CC Steam Steam Steam all fuel ‘Gas on Margin’

FRCC Capacity 23% 8% 0% 24% 1% 12% 9% 23% Over 90%

Net Gen 32% 16% 0% 28% 0% 11% 9% 3% 

Southern Capacity 41% 9% 9% 18% 1% 0% 2% 20% 50% to 70% 

Net Gen 67% 19% 4% 7% 1% 0% 2% 1%

Entergy Capacity 19% 11% 1% 28% 22% 10% 1% 8% 70% to 90%

Net Gen 35% 28% 1% 17% 13% 3% 1% 2% 

TVA Capacity 42% 18% 17% 8% 0% 0% 0% 14% 25% to 50%

Net Gen 59% 26% 14% 1% 0% 0% 0% 0%

VACAR Capacity 42% 22% 11% 4% 0% 0% 1% 19% 25% to 50%

Net Gen 54% 40% 2% 1% 0% 0% 1% 1%

Total Capacity 35% 14% 7% 16% 4% 4% 2% 17%

Southeast Net Gen 51% 27% 4% 10% 2% 2% 2% 1%

Subregional Capacity and Generation
The Southwest electric market encompasses the Arizona-New

Mexico-Southern Nevada (AZNMSNV) and the Rocky

Mountain Power Area (RMPA) subregions of the Western Electric

Coordinating Council (WECC) as designated by the North

American Electric Reliability Council (NERC). Twelve control

areas dispatch the Southwest electric grid in coordination with

the WECC’s Rocky Mountain/Desert Southwest Reliability

Coordinator. Physical and financial electricity products are

actively traded through brokers with the Palo Verde, Four

Corners, and Mead hubs as price points. Average 2004 peak prices

for the Palo Verde Hub increased 2%–3% over 2003 prices.

Average prices for the year were similar at Palo Verde and Four

Corners, and slightly higher at Mead. There are no RTO/ISO

administered markets in the region. 

The region has a surplus of generating capacity, notably in

Arizona, where transmission access to California markets is limited (see Palo Verde Transmission Development Lags Generation

Growth, below). In 2004, the regional reserve margin increased

slightly from 2003 as supply additions outpaced demand growth.

Southwest Electric Market Profile

State of the Markets Report • June 2005 121

RMPA

AZ-NM-SNV

NERC Subregions

4 Corners

$50.51

Mead

$52.16

Palo Verde

$50.11

TX

KS

NE

SD

ND

WY

MT

NV

UT

NV

CO

NM

CA

AZ

• Transmission events in Arizona

led to a review of system reliability measures. On June 14, a

disturbance on a 230-kV line

west of Phoenix tripped several

transmission lines near Palo

Verde and caused load-shedding in Arizona and 

surrounding states. More 

than 4,500 MW of generation, 

including all three nuclear units

at Palo Verde, were lost for 

periods from a few minutes to a

few days. On July 4, a fire at the

West Wing substation northwest of Phoenix reduced the

city’s power supply, forcing conservation during July and August.

A July 20 fire near the Deer

Valley substation northwest of

Phoenix caused local outages.

Consulting studies found that

the June 14 disturbance weakened a transformer at West

Wing, which contributed to the

July 4 fire. The studies recommended several system and

procedure improvements.

• Regional transmission planning

groups. Regional utilities, state

regulators and agencies, transmission users, owners, operators, and environmental groups

have been engaged in coordinated transmission planning. 

In Arizona, southern California,

southern Nevada, and Mexico,

the ad hoc Southwest

Transmission Expansion

Planning Group looked at

increasing the transfer 

capability into California. The

Southwest Area Transmission

Group (SWAT) worked on 

transmission project analysis

for the Palo Verde and the Four

Corners areas. Others involved

included the Central Arizona

Transmission Study Group and

the Colorado Coordinated

Planning Group (CCPG), which

analyzed new transmission to

support proposed generation

such as Xcel Energy’s coalfired generation at the

Comanche Station in Pueblo.

• Financial health of utilities.

New projects were slowed by

questions about the creditworthiness of regional utilities. Of

seven long-term renewable projects intended to start in 2004,

financing for five was hampered

by prospective lender’s skepticism of power purchase agreements with Nevada Power due

to the poor financial condition of

parent company Sierra Pacific

Resources.1 Southern Nevada

depends on imports for more

than half of its energy; the

remainder is purchased from

nonutility or out-of-state

resources. Demand continued

to grow in southern Nevada.2

Focal Points for 2004

Supply Demand Statistics

2003 2004 Exp. 2005

Summer Generating Capacity MW 41,646 45,588 45,726

Summer Peak Demand MW 35,815 35,280 37,826

Summer Reserves MW 5,831 10,308 7,900

Summer Reserve Margin 16% 29% 21%

Annual Load GWh 177,401 180,154 187,128

Palo Verde Hub Prices

2003 2004 5-Year

Platts $49.10 $50.09 $70.39

ICE $49.04 $50.42 NA 

Dow Jones $48.88 $50.11 $68.25

Source: Derived from Platts, IntercontinentalExchange (ICE) and Dow Jones data. 

See source note 2.

Source: Derived from WECC data. See source note 3.

Source: FERC/OMOI analysis of Dow Jones data. See source note 1.

2004 Average Hub Prices for On-peak Hours ($ per MWh)
For the Southwest, financial markets consist of both physical forwards and financial swaps. 

Though ICE financial swap volumes increased in 2004 at Palo

Verde, physical trading remained greater. Over the year, ICE

physical forwards volumes were more than two times greater

than financial swaps volumes. Only in June was ICE swaps trading greater than the physical trading volume.

122 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

The figures above illustrate day-ahead peak bilateral prices from

Platts, ICE, and Dow Jones for Palo Verde, Four Corners, and

Mead trading hubs for peak hours and days. Southwest prices

peaked on July 15, from the upper $70s/MWh at Palo Verde to

the lower $80s at Four Corners and Mead. The lowest prices

occurred in late September and in March. Prices on the

IntercontinentalExchange (ICE) for Four Corners were lowest

on March 26 and 27, whereas ICE Palo Verde prices were lowest

on September 17 and ICE Mead prices were lowest on

September 20. 

Palo Verde appeared more actively traded than Four Corners or

Mead. On ICE, Palo Verde volumes averaged 20,953 MW, peaking at 49,600 MW for December 23 and 24. Four Corners ICE

volumes averaged 3,800 MW, peaking at 14,400 MW for May 28

and 29. Mead ICE volume averaged 7,116 MW, peaking at

22,400 MW for December 3 and 4.

Southwest Electric Market Profile

SPOT MARKETS: PRICES AND VOLUMES

FINANCIAL MARKETS: PRICES AND VOLUMES

Daily Avg of Four Corners and Palo Verde On-Peak Prices

$0

$20

$40

$60

$80

$100

$120

$140

Jan

Feb

Mar

Apr

May

Jun

Jul

AugSep

Oct

Nov

Dec

$/MWh

Platts Palo Verde ICE Palo Verde

Dow Jones Palo Verde Platts Four Corners

ICE Four Corners Dow Jones Four Corners

Daily Average of Mead On-Peak Prices

$0

$20

$40

$60

$80

$100

$120

$140

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

$/MWh

Platts Mead

ICE Mead

Dow Jones Mead

Source: Derived from Platts, ICE, and Dow Jones data. See source note 4. Source: Derived from Platts, ICE, and Dow Jones data. See source note 4.

Palo Verde Swaps Prices from Trade Date Palo Verde Forward and Swaps Volume

$0

$20

$40

$60

$80

$100

$120

$140

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

$/MWh

12/15/2003

03/15/2004

06/15/2004

09/15/2004

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

Jan

FebMar

Apr

May

Jun

Jul

AugSep

Oct

Nov

Dec

MWh (thousands)

ICE Forward Volume

ICE Swaps Volume

ClearPort Swaps Volume

Source: Derived from ICE data. See source note 5. Source: Derived from ICE and Nymex data. See source note 5.
State of the Markets Report • June 2005 123

Southwest Electric Market Profile

Cumulative annual net revenue from energy for gas-fired technologies in 2004 declined from 2003. For a combined cycle

plant, revenue from energy declined 20% from 2003 and 88%

from 2000. For a combustion turbine, revenue from energy

declined 67% from 2003 and 99% from 2000. See figure this

page.

We estimate that new gas-fired combustion turbine plants in

the Southwest require $61.52 per kW per year, and gas-fired

combined cycle plants require $83.87 per kW per year, to meet

debt and equity requirements. The five-year average net revenue estimates for both gas-fired combined cycle and combustion turbine plants exceeded these levels only due to the exceptionally large revenue extracted from high-priced periods during 2000 and 2001. In 2003 and 2004, estimated net revenue for

gas-fired combined cycle and combustion turbine plants in the

Southwest was below these thresholds, which suggests that

market-based investment was not attractive.

Southwest Electric Market Profile

0.00

50.00

100.00

150.00

200.00

250.00

300.00

350.00

2000 2001 2002 2003 2004

$ / kW-year

CC Net Revenue

CT Net Revenue

CC New Entry Costs

CT New Entry Costs

Palo Verde Net Revenue from Energy

Source: Derived from Platts day-ahead gas prices for Socal Gas Large Packages and

day-ahead power prices for the Palo Verde Hub. See “Analytic Note on Net Revenue

Calculations” in the Other Material section for details.

NET REVENUE

Palo Verde Transmission Development Lags Generation Growth

During 2002 and 2003, more than 6,000 MW of

new merchant generation was connected to the

transmission grid near the Palo Verde Hub in

Arizona. By the end of 2003, grid upgrades had

increased the maximum power flow from Palo

Verde eastward (towards Phoenix) to 6,970 MW

from 3,810 MW. The westbound transfer capability of 2,800 MW (from Phoenix into California)

has not grown since the new merchant generation

was built. Westbound transfer capability was

enough to support historical levels of peak hour

power exports to California, but not more. The

Arizona Corporation Commission (ACC) reported in 2004 that merchant generators may find

themselves “stranded at the hub due to transmission limitations into California.” At least three

proposals for transmission upgrades were under

review in 2004: a second transmission line from

Palo Verde to the Devers substation in California,

a new 500-kV line into San Diego, and a series of

short-term upgrades such as new capacitors and

transformers. In its transmission assessment,

ACC staff raised reliability concerns about the

large amounts of generation built near the Palo

Verde transmission hub. Noting the extreme (but

low probability) transmission disruption that

occurred at Palo Verde in 2004 (see major topics

discussion above), ACC suggested bolstering

transmission standards for future generators built

near Palo Verde. 3
124 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Southwest Electric Market Profile

Capacity and Generation by Fuel and Prime Mover

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Capacity Net Generation

Share of Regional Total (%)

OIL CT

GAS/OIL CT

GAS CT

OIL ST

GAS/OIL ST

GAS/OIL CC

GAS ST

GAS CC

COAL ST

NUCLEAR

WIND

HYDRO

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Capacity Net Generation

Share of Regions Total (%)

El Paso Electric Co.

Sierra Pacific Resources

PNM Resources

Edison International

Tri-State G & T

Association, Inc.

UniSource Energy Corp.

Western Area Power

Administration

Salt River Project

Xcel Energy, Inc.

Pinnacle West Capital

Corp.

Source: Derived from Platts data. See source note 6.

Source: Derived from Platts data. See source note 6.

In 2003, hydro, wind, nuclear, and coal totaled 69% of total

Southwest capacity and provided 86% of net generation. The

region depends on natural gas for intermediate loads. Gas-fired

generation provided 29% of the capacity in 2003 and 14% of

annual generation. 

2003 RESOURCE MIX

2003 MARKET CONCENTRATION

The top 10 owners provided 72% of capacity and 72% of generation in the Southwest in 2003. All of the top 10 generation

owners in the Southwest are regional utilities, their affiliates, or

large municipals and cooperatives; the largest independent

power producer in the region owns less than 2% of Southwest

capacity. The largest suppliers of load in the Southwest are predominantly the largest owners of generation and are able to

cover much of their load through self-supply. 

In 2004, capacity concentration was reduced slightly as new

units at the 1,240-MW Harquahala plant entered service.

Although a few generating facilities were transferred to lenders

from their independent owners, most notably the 2,200-MW

Gila River power station and the Harquahala facility, the transfers had little impact on ownership concentration in 2004. 

2003 REGIONAL EXPORTS AND IMPORTS

Capacity and Generation of Top 10 Companies

The Southwest region was a net exporter of electricity with an

average of 4,080 MW in 2003. It exported 4,511 MW on average

to the California-Mexico subregion, while importing an average

of 431 MW from the Northwest subregion and the Southwest

Power Pool.

Average Hourly Net Interchange

External Interface Avg Avg Avg 

Exports - MW Imports - MW Net Exports

(Imports) MW

California-Mexico Subregion 4,763 252 4,511

Northwest Subregion 283 455 (172)

Southwest Power Pool 1 260 (259)

Source: Derived from Platts data. See source note 7.
State of the Markets Report • June 2005 125

Southwest Electric Market Profile

In 2004, 2,570 MW of generation (all gas-fired) and five new

transmission projects were added in the Southwest and Rocky

Mountain region.4

Generation Additions: In the Southwest/Rocky Mountain

region, five generation projects came on line and one project that

was started in 2003 received an additional two units. The four

largest generation additions cost roughly $1.5 billion. In southern

Nevada two combustion turbine plants, Silverhawk and Bighorn,

came on line. Both Silverhawk and Bighorn are located in

Power’s Service territory and together provide 1,046 MW of summer capacity. The Rocky Mountain Energy Center, a 516-MW

plant, came on line in Xcel Energy’s service territory to serve

wholesale energy markets in Colorado. Units 2 and 3 at the

Harquahala plant came on line, adding another 825 MW of

capacity in Arizona. Capacity additions in 2004 were less than in

each of the two previous years.5

Transmission Additions: Five transmission projects were completed, three in the Southwest and two in the Rocky Mountain

region. The largest transmission expansion was Tucson Electric

Power Co.’s 31-mile 354-kV line from Winchester, Ariz., to Vail,

Ariz., that was completed in June 2004. In the Rocky Mountains,

the Lamar, Colo., 210-MW DC tie line connects Xcel Energy’s

Southwestern Public Service Co. (SPS) in the eastern interconnection with Xcel’s Public Service Co. of Colorado system in the west,

adding 210 MW of power transfer capability in both directions. 

The Green Valley-Spruce 230-kV line came on line in May 2004.

Six projects are under construction and expected to become active

in 2005. Two of these are in the AZNMSNV area, one of which is

from Palo Verde to Pinal West (in the Phoenix region). The other

four projects are in the Rocky Mountain region.6

Arizona Public Service (APS) continued efforts to transfer merchant power plants to its utility rate base. In 2004, APS reached

a settlement with intervenors in its proposal to acquire from an

affiliated company five Arizona merchant power plants, totaling 1,790 MW. It also announced the intent to purchase the

450 MW Sundance Generating Station from PPL Corporation.

The Arizona Corporation Commission (ACC) stated it would

address the implications of the asset transfers on competition

in workshops to discuss resource planning and acquisition

issues.

In its 2003 general rate case filing with the ACC, APS proposed

to acquire five merchant plants built by its affiliate, Pinnacle

West Energy Corporation (PWEC). The five plants totaled

approximately 1,790 MW including the 1,060 MW Redhawk

Units 1 and 2, the 650 MW West Phoenix Units 4 and 5, and

the 80 MW Saguaro Unit 3. On August 18, 2004, APS entered

into a settlement with 21 parties–including ACC staff, customer groups, and merchant generators. Under the settlement,

APS would recover $700 million in its rates as the cost for the

power plants (a discount of $148 million from book value),

issue a request for proposal for an additional 1,000 MW in 2005

to meet electricity demand growth, and not build any power

plants that went into service before 2015 (subject to a “safety

mechanism” where it must prove to the ACC that it cannot

obtain needed resources on acceptable terms in the wholesale

market). The third provision, a so-called “self-build moratorium,” did not preclude APS from buying generating plants from

other, unaffiliated companies. 

In November 2003, APS issued a request for proposal for longterm power supply resources and selected PPL Corporation’s

Sundance offer. In mid-2004, APS said the utility would face a

1,000 MW shortfall in 2007, even after the Sundance acquisition. In June, APS entered a $190 million purchase agreement

with PPL and filed an application with the ACC to finance the

costs.7 APS announced its intention to include Sundance

acquisition costs in its next rate case, to be filed in late 2005.

Capacity Additions

-1000

0

1000

2000

3000

4000

5000

6000

7000

2002 2003 2004

MW

RMPA

Additions

AZNMSNV

Additions

RMPA

Retirements

AZNMSNV

Retirements

RMPA

Mothballed

GENERATION AND TRANSMISSION ADDITIONS AND RETIREMENTS

Source: Derived from Platts, EIA, and Nevada State Office of Energy and Arizona

Corporation Commission (Summer capacity).

Increasing Market Power, Arizona Public Service Acquires Local Assets
Endnotes

126 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Southwest Electric Market Profile

1. Prices are Dow Jones firm day-ahead on-peak prices for the locations identified.

2. Platts Megawatt Daily, IntercontinentalExchange (ICE) and Dow

Jones prices are firm day-ahead on-peak for the Palo Verde Hub. 

3. Data are from WECC, “Summary of Estimated Loads and

Resources,” July 2004 and May 2005.

4. Platts Megawatt Daily, ICE and Dow Jones prices are for firm dayahead on-peak delivery to identified locations. 

5. ICE on-peak forward and swap prices and volumes are for Palo

Verde and include monthly, dual monthly, quarterly, and calendar

year contracts traded for 2004. New York Mercantile Exchange

(Nymex) ClearPort on-peak swaps volumes are for Palo Verde

and are traded by month. 

6. Data from Platts PowerDat, RDI Modeled Production Costs

dataset for calendar year 2003 reflecting self-reporting from all

utility and nonutility electric power generating facilities with

nameplate capacity of 50 MW or more.

7. Average hourly interchange data derived from Platts PowerDat

reporting of FERC Form 714 data.

Disclaimer: This report contains analyses, presentations, and 

conclusions that may be based on or derived from the data sources

cited, but do not necessarily reflect the positions or recommendations

of the data providers. 

1 Nevada State Office of Energy.

2 The electric utility for most of southern Nevada, Nevada Power,

experienced peak demand growth of 3.3% in 2004 and customer

growth of 5%. Sierra Pacific Resources Annual Report 2004,

Nevada Power Facts,

http//www.nevadapower.com/company/facts.

3 Third Biennial Transmission Assessment, Arizona Corporation

Commission, Nov. 30, 2004, 54.

4 Capacity Additions and Retirements are for calendar year 2004,

based on Platts and EIA net summer capacity estimates and FERC

staff research. They may differ from the Summer Generating

Capacity in the Supply Demand Statistics table. Summer

Generating Capacity may be projected for the summer peak, may

omit some calendar year additions, and may reflect actual demonstrated capacity and deratings.

5 Platts PowerDAT, NEWGen as of March 1, 2005; EIA Form 860;

2005 Status of Energy in Nevada Report; ACC Third Annual

Biennial Transmission Assessment; FERC staff research. Data are

for summer capacity unless otherwise indicated.

6 NERC Electricity Supply & Demand database 2004, updates from

NERC as of April 19, 2005; WEstern Electricity Coordinating

Council, summary of “10-Year Coordinated Plan,” September

2004, which involved the following groups in planning transmission for the Southwest: Southwest Area Transmission Planning

group (SWAT), SOuthwest Transmission Expansion Planning

(STEP), and Colorado Coordinated Planning Group (CCPG). Data

are for new transmission lines 230 kV and above unless otherwise

indicated.

7 Although the costs of Sundance Acquisition were not included in

the 2003 general rate case, analysts have noted that a Power

Supply Adjustor (PSA) proposed in the rate case may provide APS

ability to collect some fuel and purchased power costs related to

the purchase agreement before the next general rate case 

decision.

Source notes
The Southwest Power Pool (SPP) electric market comprises

the SPP reliability region, as designated by the North

American Electric Reliability Council (NERC). Working in

concert with the region’s reliability coordinator, 15 control

areas dispatch generation on the SPP electric grid. Market 

participants also trade physical electricity bilaterally, either

directly or through brokers. Average 2004 peak prices were 8%

higher than in 2003, according to Platts, which publishes energy figures for an SPP North pricing point.

NERC statistics indicate that the region has adequate capacity

reserves. 

Southwest Power Pool (SPP) Electric Market Profile

State of the Markets Report • June 2005 127

SPP • NERC Region 

SPP North

$45.19 MO

MS

TX

NM

OK

CO

KS

AR

LA

NE

IA

IL

TN

• Work continues on the SPP

regional transmission

organization (RTO),

approved by FERC on

October 1, 2004. SPP has

completed its market design

and protocols, along with

the system design. Market

applications are being

worked on. SPP is set to file

a new tariff with FERC in

June 2005 and plans to go

live March 1, 2006.

• Gearing for a push. SPP

named a new CEO, Nick

Brown, in February 2004

and seated an independent

(all nonstakeholder) board

in May. SPP also hired 27

people, boosting the staff to

131. SPP doubled its assets

in 2004 by floating $25 million in senior notes.

• Locational price signals could

spur transmission investment

in the region. SPP control

areas called 317 transmission

loading relief (TLR) events

level 3 or above in 2004.

Eleven of these TLRs reached

level 5, which led to curtailment of firm point-to-point

and network transmission

service and suggests that

several significant constrained

flowgates exist in SPP. Better

locational price information

and enhanced regional planning through the RTO and

Regional State Committee is

expected to encourage transmission investment.

Focal Points for 2004

SPP North Prices

2003 2004 5-Year

Platts $41.66 $45.19 $38.70

Source: Derived from Platts data. See source note 1.

Source: Derived from SPP data. See source note 2.

Source: Derived from Platts data. See source note 1.

2004 Average Regional Prices for On-peak Hours ($ per MWh)

2003 2004 Exp. 2005

Summer Generating Capacity MW 45,929 45,242 45,937

Summer Peak Demand MW 40,214 39,893 40,906

Summer Reserves MW 5,715 5,349 5,031

Summer Reserve Margin 21% 20% 19%

Annual Load GWh 185,574 191,829 194,180

Supply Demand Statistics
128 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Southwest Power Pool (SPP) Electric Market Profile

SPOT MARKETS: PRICES AND VOLUMES

Daily Average of On-Peak Prices

$0

$20

$40

$60

$80

$100

$120

$140

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

$/MWh

Platts SPP North

Source: Derived from Platts data. See source note 1.

SPP Regional State Committee Hits the Ground Running in 2004

The SPP Regional State Committee (RSC) was formed in April

2004 to provide input from state regulators on regional issues.

The committee, which is funded by the SPP, is made up of public utility commissioners from Arkansas, Kansas, Missouri,

Texas, and Oklahoma. A member from New Mexico resigned

based on concerns of his state’s Attorney General. The chairman of the RSC is Denise Bode, who also chaired the

Oklahoma Corporation Commission.

The costs and benefits of SPP’s transition to a regional transmission organization, including implementation of an

imbalance market, have been studied by a working group of

RSC staff and SPP stakeholders. They also looked at ways to

make cost-benefit regulatory filings by SPP utilities easier. A

final report was completed in May 2005.

In addition, an RSC working group developed options for

allocating the costs of transmission upgrades for designated

resources. A funding policy they recommended was adopted

by the SPP board in January 2005. The new policy allocates

33% of base plan upgrade costs to region-wide transmission

rates. The remainder is recovered in zonal rates for areas

benefiting from the upgrade. SPP filed tariff revisions to

implement the transmission cost allocation policy with

FERC on February 28, 2005.1 The commission approved the

policy in May 2005.

Day-ahead peak bilateral prices peaked on July 13 at $75 per

MWh, as forecast temperatures were expected to break 100

degrees in Oklahoma and the mid-90s in many areas throughout

the region, according to figures drawn from Platts Megawatt Daily.

Prices were lowest on January 2, at $21 per MWh, as temperatures

were unseasonably warm for that period. No major pricing

events occurred in SPP in 2004. 

Platts SPP North pricing point is not actually traded. Platts

reported only one day, October 29, with bilateral trading volume.

The SPP North Hub does not appear as the pricing location for

any transactions reported to FERC in the Electric Quarterly

Report in 2004.

Capacity and Generation by Fuel and Prime Mover

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Capacity Net Generation

Share of Regional Total (%)

OIL CT

GAS/OIL CT

GAS CT

OIL ST

GAS/OIL ST

GAS/OIL CC

GAS ST

GAS CC

COAL ST

NUCLEAR

WIND

HYDRO

Source: Derived from Platts data. See source note 3.

In 2003, hydro, wind, nuclear, and coal totaled 49% of total SPP

capacity and provided 80% of net generation. The region

depends on gas-fired, combined-cycle capacity to meet intermediate and peak loads, providing 17% of the capacity in 2003

and contributing 8% of annual net generation. 

SPP is interconnected with ERCOT, WECC, SERC, MAPP and

MAIN and was a net importer of energy in 2004. 

2003 RESOURCE MIX AND IMPORTS

Average Hourly Net Interchange

Avg. Exports Avg. Imports Avg. Net

MW MW Exports(Imports)

2,200 4,958 (2,758)

Source: Derived from SPP data.
State of the Markets Report • June 2005 129

Southwest Power Pool (SPP) Electric Market Profile

2003 MARKET CONCENTRATION

Capacity and Generation of Top 10 Companies

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Capacity Net Generation

Share of Regions Total %

USCE Little Rock District

Grand River Dam

Authority

Calpine Corp.

Aquila, Inc

Cleco Corp.

Great Plains Energy Corp.

Xcel Energy, Inc.

OGE Energy Corp.

Westar Energy Inc.

American Electric Power

Co., Inc

Source: Derived from Platts data. See source note 3.

The top ten owners provided 73% of capacity and 79% of generation in SPP in 2003. Nine of the top ten generation owners in SPP

were regional utilities, their affiliates, or large municipals and

cooperatives. In 2004, capacity concentration changed little

because very few plants were added or retired.

The largest load-serving entities in SPP were also the largest

owners of generation and covered much of their load through

self-supply. 

SPP had 432 MW of wind capacity operating in 2004. Most of

the capacity came on line in the last three years. FPL Energy

Inc. is the largest owner and operator, with 214 MW. The

developers of other major wind farms are Cielo Wind Power,

LLC (140 MW) and Zilkha Renewable Energy (74 MW).

Aquila, Oklahoma Municipal Power Authority, Southwestern

Public Service, and Western Farmers Electric Cooperative have

signed power purchase agreements to buy power from these

wind farms. In November 2004, Public Service of Oklahoma

(PSO) and sister company Southwestern Electric Power issued

a solicitation for up to 250 MW of renewable resources.

In 2005, wind generating capacity in SPP is expected to triple.

FPL Energy Inc. is adding 107 MW, while Cielo Wind Power

LLC will add an additional 180 MW, and Zilkha Renewable

Energy is building 120 MW. Newcomers include Great Plains

Windpower LLC (320 MW), Elk River Windfarm LLC (150

MW), Chermac Energy Group (137 MW), Padoma Wind

Power LLC (120 MW), enXco Inc. (100 MW), Central Plains

Power LLC (100 MW), and Grand Vent Wind Systems (50

MW). Southwestern Public Service leads the list of utilities

signing power purchase agreements with projects coming on

line in 2005, with 360 MW. Other major buyers of wind power

are Westar in Kansas (200 MW), Empire District Electric in

Missouri (150 MW), and Kansas City Power & Light in

Missouri (100 MW). By the end of the year, American Electric

Power’s subsidiary, Public Service of Oklahoma, is expected to

be the largest buyer of wind power in Oklahoma, with 227 MW

under 10- and 20-year contracts.4

Wind Power Developers Find SPP Fertile Ground

Generation Additions. Three generation projects, totaling

1,214 MW of capacity, came on line in SPP. The largest is the

1,144 MW natural gas Redbud Power Plant, which cost about

$856 million to build. The other plants are a 60 MW wind project and a 10 MW oil plant. The capacity additions in 2004 were

fewer than in the two previous years. Twenty-three MW of generation were mothballed and 20 MW retired.2

Fifteen projects in SPP totaling 1,155 MW were under construction or development and expected to be on line between 2005

and 2007. About 1,060 MW of wind projects were due to be

completed in 2005. The remaining capacity additions are gasfired. 

Transmission Additions. Two new transmission projects, totaling 131 miles, were completed in 2004. Both projects were built

by Southwestern Public Service Co.3

Capacity Additions

-1000

-500

0

500

1000

1500

2000

2500

3000

3500

4000

2002 2003 2004

MW

SPP Additions

SPP Retirements

SPP Mothballed

GENERATION AND TRANSMISSION ADDITIONS AND RETIREMENTS

Source: Derived from EIA and Platts data. See source note 4.
130 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Southwest Power Pool (SPP) Electric Market Profile

1. Prices are from Platts Megawatt Daily for day-ahead on-peak

delivery at the identified pricing locations.

2. Data are from NERC’s 2004 ES&D Database and Platts

PowerDat (annual net generation). Generation capacity

excludes all derates of resources and imports. 

3. Data from Platts PowerDat, RDI Modeled Production Costs

dataset for calendar year 2003 reflecting self-reporting from all

utility and nonutility electric power generating facilities with

nameplate capacity of 50 MW or more.

4. Data from Energy Information Administration (EIA) Form 860,

Platts NewGen and Platts PowerDat. All generation is summer

capacity unless otherwise indicated.

Disclaimer: This report contains analyses, presentations, and 

conclusions that may be based on or derived from the data

sources cited, but do not necessarily reflect the positions or 

recommendations of the data providers. 

1 SPP, SPP Regional State Committee minutes, SPP Filing in ER05-652,

February, 28, 2005. 

2

Platts PowerDAT, NewGen as of March 1, 2005, EIA Form 860. Data are for

summer capacity unless otherwise indicated. Capacity Additions and

Retirements are for calendar year 2004, based on Platts and EIA net summer capacity estimates and FERC staff research. They may differ from the

Summer Generating Capacity in the Supply Demand Statistics table.

Summer Generating Capacity may be projected for the summer peak,

may omit some calendar year additions, and may reflect actual demonstrated capacity and deratings.

3

NERC ES&D Database 2004; Updates from NERC as of April 19, 2005.

Transmission data are for new transmission lines 230kV and above

unless otherwise indicated.

4

Platts NewGen, Amercian Wind Energy Association, Megawatt Daily

March 8, 2005.

Endnotes

Source notes

Annual net revenues from energy for gas-fired technologies were

below the five-year average for the third consecutive year. For a

combined cycle, revenues from energy increased 4% from 2003

and 54% from 2000. For a combustion turbine, revenues from

energy declined 67% from 2003 and 98% from 2000.

We estimate that new gas-fired, combustion-turbine plants in SPP

require $61.21/kW-yr, and gas-fired, combined-cycle plants

require $83.43/kW-yr, to meet debt and equity requirements.

SPP 2004 net energy revenue estimates were well below these

thresholds. This suggests that market-based investments in new

generation were not attractive.

0.00

10.00

20.00

30.00

40.00

50.00

60.00

70.00

80.00

90.00

2000 2001 2002 2003 2004

$ / kW-year

CC Net Revenue

CT Net Revenue

CC New Entry Costs

CT New Entry Costs

SPP Net Revenue from Energy

Source: FERC/OMOI analysis of Platts day-ahead gas parices for NGPL (Midcont.)

and day-ahead power prices for SPP. See “Analytic Note on Net Revenue

Calculations” in the Other Material section for details.

NET REVENUE
The Energy Reliability Council of Texas (ERCOT), as designated by the North American Electric Reliability Council

(NERC), constitutes the ERCOT electric market. In 2002,

ERCOT expanded its role of central dispatch within a single control area, ensuring transmission reliability and open wholesale

access, to oversee the ongoing restructuring of the Texas electric

industry—including the development and operation of most of

the Texas competitive retail market. ERCOT runs balancing

energy and ancillary service markets with zonal congestion

management. Market participants trade electricity bilaterally

either directly or through brokers and the

IntercontinentalExchange (ICE), generally using the ERCOT

Hub as the pricing point. Average 2004 peak prices for the

ERCOT zones have changed little from 2003. 

The region currently has excess capacity. In 2004, the regional

reserve margin increased from 2003 as new plants entered commercial operation. Several companies are seeking permission

from ERCOT to retire older, inefficient generating plants. The

small differences in average zonal prices indicate some congestion among zones. What is not shown is much more significant

intra-zonal congestion.

Texas (ERCOT) Electric Market Profile

State of the Markets Report • June 2005 131

North 

Houston 

South

West

Northeast

Zones

West

$47.12

AR

LA

OK

North

$47.89

South

$46.88

Northeast

$47.00

Houston

$48.17

TX

NM

• Competitive electricity markets

in Texas are maturing. The

Public Utility Commission of

Texas (PUCT) described the 

current state of electric market

competition in a statutorily

mandated biannual report to

the Texas legislature. The PUCT

claimed that Texas has the

most robust, well-functioning

retail market in the United

States. Texas has seen healthy

investment in new generation

and entry of retail providers

offering electricity at competitive prices. The report noted

that electricity prices have

increased because of higher

natural gas prices.

• An independent market monitor

for the ERCOT market was

proposed by the PUCT in June,

but dropped from a final rule

issued in December 2004

because the issue was expected to be taken up by the Texas

Legislature in its current session. A Senate bill laying out

provisions for developing an

independent market monitor

for ERCOT passed the Texas

Senate on April 14, 2005.

• PUCT is investigating bidding

practices after off-peak prices

jumped to $400/MWh on

November 29, 2004. TXU Corp.

is the subject of several 

investigations and lawsuits

about its marketing practices

and bidding in ERCOT’s balancing energy market. Texas

Commercial Energy, a retail

electric supplier, sued, claiming

that TXU and other suppliers

drove up prices during severely

cold weather in February 2003,

bankrupting the company. An

interim report of the Market

Oversight Division of the Public

Utility Commission of Texas

(PUCT) did not find evidence 

of wrongdoing. The inquiry

remains open. In a related

development, two Texas retail

providers sued several electricity suppliers in February 2005,

alleging price fixing and 

collusion.

Focal Points for 2004

Supply Demand Statistics

2003 2004 Exp. 2005

Summer Generating Capacity MW 73,882 73,855 70,639

Summer Peak Demand MW 59,996 58,531 59,702

Summer Reserves MW 13,886 15,324 10,937

Summer Reserve Margin 23% 26% 18%

Annual Load GWh 283,868 289,146 294,928

ERCOT Prices

2003 2004 5-Year

Platts $46.49 $47.32 $41.08

ICE $46.78 $47.55 NA 

ERCOT North $48.16 $47.89 NA

Source: Derived from ERCOT, Platts and IntercontinentalExchange (ICE) data. See

source note 2.

Source: Derived from ERCOT and NERC data. See source note 3.

Source: Derived from ERCOT data. See source note 1.

2004 Average Zonal Prices for On-Peak Hours ($ per MWh)
For ERCOT, financial markets consist of physical forwards. In

2004, trading of ICE ERCOT monthly products amounted to 330

GWh, which was 20% of the 1,475 GWh that was traded on a

next-day basis.

132 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

The graphs illustrate day-ahead peak bilateral prices from Platts

and ICE as well as ERCOT’s real-time balancing energy prices.

ERCOT’s major 2004 pricing event was on November 29, when

15-minute, on-peak prices rose to almost $140/MWh and offpeak prices jumped to more than $400/MWh. The PUCT initiated an investigation of this price spike, focusing on the bidding

behavior of TXU. In early March 2004, congestion on the

ERCOT grid prompted operators to re-dispatch generation in the

ERCOT west zone. The balancing energy price in the west zone

went negative because some generators that were re-dispatched

submitted negative-price bids to avoid having their output

reduced.

ERCOT reached its 2004 peak hourly load of 58,531 MW on

August 3. In 2004, the daily peak-load hours averaged 36,355

MW. In bilateral trading, Platts reported that volume for the

ERCOT market averaged 1,794 MW and peaked on July 29 at

4,600 MW; ICE said the trading volume averaged 6,193 MW and

peaked on December 10 at 31,200 MW.

Texas (ERCOT) Electric Market Profile

SPOT MARKETS: PRICES AND VOLUMES

FINANCIAL MARKETS: PRICES AND VOLUMES

Daily Average of On-Peak Prices

$0

$20

$40

$60

$80

$100

$120

$140

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

$/MWh

Platts ERCOT

ICE ERCOT

Daily Average of Balancing Energy On-Peak Prices

$0

$20

$40

$60

$80

$100

$120

$140

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

$/MWh

ERCOT North

ERCOT South

ERCOT West

ERCOT Houston

ERCOT Northeast

ERCOT West: -$28

All Zones: $150

Source: Derived from Platts and ICE data. See source note 4. Source: Derived from ERCOT data. See source note 1.

Forward Prices from Trade Date Forward Volume

$0

$20

$40

$60

$80

$100

$120

$140

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

$/MWh

12/15/2003 03/15/2004

06/15/2004 09/15/2004

0

20

40

60

80

100

120

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

NovDec

MWh (thousands)

ICE Forward Volume

Source: Dervied from ICE data. See source note 5. Source: Derived from ICE data. See source note 5.
State of the Markets Report • June 2005 133

Texas (ERCOT) Electric Market Profile

Capacity and Generation by Fuel and Prime Mover

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Capacity Net Generation

Share of Regional Total (%)

OIL CT

GAS/OIL CT

GAS CT

OIL ST

GAS/OIL ST

GAS/OIL CC

GAS ST

GAS CC

COAL ST

NUCLEAR

WIND

HYDRO

2003 RESOURCE MIX

In 2003, hydro, wind, nuclear, and coal represented 29% of

total ERCOT capacity and provided 53% of net generation.

The region depends on gas-fired capacity to meet intermediate

and peak loads, providing 66% of the capacity in 2003 and contributing 45% of annual net generation. The remainder is

served by generators that can switch between gas and oil.

Source: Derived from Platts data. See source note 6.

As this graph shows, the top 10 owners provided 78% of capacity

and 76% of generation in ERCOT in 2003. Six of the top 10 generation owners in ERCOT are regional utilities, their affiliates, or

large municipals and cooperatives. The other four are independent power producers or utility affiliates that have built or acquired

generating assets outside of their traditional service territories. 

Capacity concentration declined in 2004 as a number of asset sales

closed. Although some sales were one-asset deals, two large portfolios were transferred to private equity owners. In July, AEP sold

the majority of its Texas Central Portfolio to a joint venture of

Sempra Energy Partners and Carlyle/Riverstone Global Energy

and Power Fund. In December, CenterPoint Energy Inc. sold the

majority of its Texas Genco assets to GC Power Acquisition LLC,

an entity owned in equal parts by affiliates of The Blackstone

Group, Hellman & Friedman LLC, Kohlberg Kravis Roberts & Co.

L.P., and Texas Pacific Group. Both AEP and CenterPoint recently received regulatory approval to close the sale of their ownership

shares in the South Texas Project Electric Generating Station,

which has two nuclear reactors producing 2,500 MW of power.

2003 MARKET CONCENTRATION

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Capacity Net Generation

Share of Regions Total (%)

Lower Colorado River

Authority

Exelon Corp.

Austin Energy

International Power PLC

FPL Group, Inc.

American Electric Power

Co., Inc

City Public Service Board

of San Antonio

Calpine Corp.

CenterPoint Energy Inc.

TXU Corp.

Capacity and Generation of Top 10 Companies

Source: Derived from Platts data. See source note 6.

The ERCOT market has a supply offer cap of $1,000/MWh as

well as a $1000/MWh cap for ancillary services. Although

ERCOT does not mitigate supply offers, the market clearing

price for energy is adjusted when balancing energy bids are

exhausted, and there is no zonal congestion. The clearing

price is recalculated after removing the highest priced 5% of

the power in the bid stack. The resulting price is then multiplied by 1.5 to account for scarcity. Suppliers with offers

above the adjusted price are paid as bid. The clearing price

adjustment occurred infrequently from its inception in June

2003 until fall 2004. Price adjustments have become more frequent since October 2004 because of changes in bidding

strategies. This trend is part of the PUCT’s ongoing investigation of TXU bidding practices.

Offer Mitigation
Estimated annual net revenue from energy for gas-fired technologies in 2004 was below the five-year average for the third

consecutive year. For combined-cycle plants, revenue from

energy declined 18% from 2003 and 71% from 2000. For combustion turbine plants, revenue from energy declined 81%

from 2003 and 99% from 2000.

We estimate that new gas-fired combustion turbine plants in

ERCOT require $60.66/kW-year, and gas-fired combined cycle

plants require $82.64/kW-year, to meet debt and equity

requirements. Estimated ERCOT 2004 net energy revenue did

not meet these requirements, which suggests that market-based

investments in new generation were not attractive.

0.00

10.00

20.00

30.00

40.00

50.00

60.00

70.00

80.00

90.00

2000 2001 2002 2003 2004

$ / kW-year

CC Net Revenue

CT Net Revenue

CC New Entry Costs

CT New Entry Costs

ERCOT Net Revenue from Energy

134 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Texas (ERCOT) Electric Market Profile

Source: FERC/OMOI analysis of Platts data. See “Analytic Note on Net Revenue

Calculations” in the Other Material section for details. 

NET REVENUE

REGIONAL EXPORTS AND IMPORTS

ERCOT is linked with the Southwest Power Pool (SPP) in the

Eastern Interconnection by two AC-DC-AC ties, with a total

transfer capability of 860 MW. In addition, Tenaska has 1,800

MW of generating capacity that can be electrically connected with

either ERCOT or SPP. ERCOT was a net importer of energy in

2004 with average imports of 449 MW over the DC ties with SPP.

Hourly Net Interchange

-External Max Max Avg. Net Exports

Interface Exports - MW Imports - MW (Imports) MW

DC ties to SPP 898 755 (449)

Source: Derived from ERCOT data.

Nodal Market Design in the Works

The Texas Nodal Team (TNT) of ERCOT stakeholders

spent 2004 developing a major redesign of the wholesale

market. In September 2003, the Public Utility

Commission of Texas had ordered them to design sweeping wholesale-market revisions.1 Major enhancements

include a day-ahead market, resource-specific (instead of

portfolio) bid curves, assignment of congestion cost to specific resources causing congestion, nodal energy prices for

resources, zonal energy prices for loads, tradable financial

congestion rights, and pricing safeguards. In November

2004, a PUCT-ordered cost-benefit study found potential

benefits to market redesign.2 ERCOT filed a redesign proposal in March 2005.3 Also in November 2004, an assessment of ERCOT market operations by market adviser

Potomac Economics documented inefficiencies in

ERCOT’s current zonal congestion-management system

and real-time operations.4 The report suggested that the

inefficiencies will be significantly reduced and real-time

operations improved with a move from a zonal to a nodal

system.
State of the Markets Report • June 2005 135

Texas (ERCOT) Electric Market Profile

GENERATION AND TRANSMISSION ADDITIONS AND RETIREMENTS

In 2004, ERCOT utilities added 2,358 MW of generating capacity, mothballed 937 MW, and retired 1,204 MW.5

Generation Additions. In ERCOT, seven generation projects

came on line in 2004. The two largest plants were both independent power producers (IPPs). The Wise County Power

plant (675 MW) and the Deer Park Energy Center (568 MW)

are both gas-turbine plants. The largest utility plant is San

Antonio’s Leon Creek gas-turbine plant, with a capacity of 298

MW. The Parkdale plant, a 330-MW natural gas plant owned

by TXU, was the largest single retirement. TXU also mothballed 814 MW of generation. Capacity additions in 2004 were

less than in the two previous years. 

Transmission Additions. ERCOT utilities were expected to

add 1,000 circuit miles of transmission lines in 2004. This number includes 158 miles of 345-kV lines, 809 miles of 138-kV lines

and 33 miles of 69-kV lines. ERCOT claims that this is a far

greater expansion of the transmission infrastructure than in

any other region in North America. 6 Source: Derived from EIA and Platts data. See source note 7.

CenterPoint sold Texas Genco Holdings, its wholesale

power generation unit, to a joint venture owned by four

private equity firms in 2004. Originally, Reliant Energy

was expected to execute first-right-of-refusal to purchase

the assets, but Reliant had too much debt on its books.

Because the sale was required as part of deregulation

agreements in Texas, CenterPoint sought another buyer. 

GC Power Acquisition, a partnership of Texas Pacific

Group, Hellman & Friedman, the Blackstone Group, and

Kohlberg Kravis Roberts & Co., won over other bidders

including another private equity consortium, with a $3.65

billion bid, making it the largest U.S. power deal by a

financial buyer. 

The deal closed in December, completing the acquisition

of 11 power plants with a generating capacity of more than

13,000 MW. The next step, approval by the Nuclear

Regulatory Commission in 2005, completed the acquisition of CenterPoint’s share of the South Texas Project

nuclear facility. 

In the meantime, GC Power Acquisition, known as Texas

Genco LLC, announced plans to retire six plants in its

portfolio that have been mothballed or used minimally in

the past couple of years. ERCOT approved the plan for

most of the units but is discussing reliability must run

(RMR) status for continued operation of a single unit in

the portfolio accounting for 740 MW. 7

Centerpoint Asset Sales and Retirements

Capacity Additions

-4000

-2000

0

2000

4000

6000

8000

2002 2003 2004

MW

ERCOT

Additions

ERCOT

Retirements

ERCOT

Mothballed
136 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Texas (ERCOT) Electric Market Profile

Source notes

1. Prices are ERCOT on-peak balancing prices for the zones identified. Data located at

http://www.ercot.com/ercotPublicWeb/PublicMarketInformatio

n/FileSystem.cfm?SubDir=mos/Operating_Day_Report&Title=

Operating%20Day%20Reports.

2. Platts Megawatt Daily and IntercontinentalExchange (ICE)

prices are day-ahead on-peak for the ERCOT Hub. ERCOT onpeak balancing prices are for ERCOT North. 

3. Data are from NERC’s 2004 ES&D Database and Platts

PowerDat (annual net generation). 2004 data are from ERCOT.

Generation capacity excludes all derates of resources and

imports. 

4. Platts Megawatt Daily and ICE prices are day-ahead on-peak for

ERCOT. 

5. ICE on-peak forward and swap prices and volumes are for

ERCOT and include monthly, dual monthly, quarterly, and calendar year contracts traded for 2004. Omission of the March 15

and September 15, 2004 curves is due to insufficient trading

volumes. 

6. Data from Platts PowerDat, RDI Modeled Production Costs

dataset for calendar year 2003 reflecting self-reporting from all

utility and nonutility electric power generating facilities with

nameplate capacity of 50 MW or more.

7. Data from Energy Information Administration (EIA) Form 860,

Platts NewGen and Platts PowerDat. All generation is summer

capacity unless otherwise indicated.

Disclaimer: This report contains analyses, presentations and 

conclusions that may be based on or derived from the data

sources cited, but do not necessarily reflect the positions or 

recommendations of the data providers. 

1 PUCT, Project No. 26376, Rulemaking Proceeding on Wholesale

Market Design Issues in the Electric Reliability Council of Texas,

September 22, 2003.

2 Tabors Caramanis & Associates and KEMA Consulting Inc., Market

Restructuring Cost-Benefit Analysis: Final Report, November 30,

2004.

3 Texas Nodal Team, filing before the PUCT, March 18, 2005.

4 Potomac Economics Ltd., Adviser to the Market Oversight

Division, Public Utility Commission of Texas, 2004 Assessment of

the Operation of the ERCOT Wholesale Electricity Market,

November 2004.

5 Capacity Additions and Retirements are for calendar year 2004,

based on Platts and EIA net summer capacity estimates and FERC

staff research. They may differ from the Summer Generating

Capacity in the Supply Demand Statistics table. Summer

Generating Capacity may be projected for the summer peak, may

omit some calendar year additions, and may reflect actual demonstrated capacity and deratings.

6 ERCOT, Report on Existing and Potential Electric System

Constraints and Needs Within the ERCOT Region, October 1, 2004.

7 Trade press reports. 

Endnotes
NATURAL GAS MARKETS IN 2004

State of the Markets Report • June 2005 137

The State of the Markets Reportcontains individual profiles on natural gas trading at the

Henry Hub and five major regions: Northeast, Southeast, Midwest, South Central, and the West.
138 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Natural Gas Markets National Overview

NATIONAL OVERVIEW

Nationally, five keys to understanding U.S. natural gas markets in 2004 were:

Natural gas prices rose 7 percent in 2004, following an increase of 63 percent in 2003. 

This price rise came during a year of increasing oil prices and mild weather.

Natural gas suppliers responded to higher prices by increasing efforts to find new supplies.

Suppliers increased exploration, developed sources previously deemed too expensive, and increased imports, 

especially of liquefied natural gas (LNG). Exploration and development expenditures were 45 percent higher in 2004 than

the average in 2001 and 2002.

The natural gas industry continued to build its infrastructure.

Investment in interstate pipeline transmission capacity in 2004 was $2.1 billion, down from $3.5 billion in 2003. 

Most of the difference was due to completion of the Kern River expansion in 2003.

Financial gas markets grew. 

During the year, financial platforms offered a wide range of new products, both attracting financially oriented traders

and allowing companies to hedge geographic and seasonal risk more robustly than before.

Information issues remained important. 

Natural gas price indices improved, but markets remained sensitive to key supply indicators, especially the Energy

Information Administration (EIA) storage report. 

West

South Central

Midwest

Southeast

Northeast
El Paso

Permian

$5.34

$0.28 Pricing Point

Current Price

1-year price differential

This year - last year

Basis

NW Sumas $5.15

$0.46

Malin

$5.35

$0.45

PG&E

Citygate

$5.75

$0.52

SoCal Border

$5.51

$0.43

El Paso

San Juan

$5.18

$0.62

Kern River Opal

$5.19

$0.88

AECO Hub

$5.04

$0.33

Waha Hub

$5.38

$0.21

Panhandle

Tex-Okla

$5.45

$0.28

Katy Hub

$5.67

$0.31

Tennessee 

Zone 0

$5.64

$0.38

Henry Hub $5.85

$0.41

Tetco M-1

$5.93

$0.38

Chicago

Citygate

$5.85

$0.30

Dawn

$6.08

$0.30

Niagara

$6.20

$0.26 Algonquin

Citygate

$6.86

$0.34

Transco

Zone 6 - NY $6.81

$0.36

Columbia 

Pool

$6.14

$0.45

$0.31

$0.04

$0.32

$0.33

$0.16

$0.13

$0.29

$0.03

$0.40

$0.27

$0.81

$0.23

$0.12

$0.67

$0.05

$0.96 $0.00

$0.96

$0.18

$0.20

$0.39

$0.24

Henry Hub Prices

Natural gas prices in 2004 averaged $5.86 per million

British thermal units (MMBtu) at the Henry Hub. 

This was 7 percent higher than the 2003 average of $5.47

per MMBtu, which in turn was 63 percent higher than in

2002 (see Figure 1). 

Henry Hub prices remained stable during cold weather in

the Northeast in January. Local prices rose, but national

prices did not. This pattern occurs when downstream

buyers face limited transportation capacity from producing regions, but there is no national shortage of supply. In

that case, prices in the production area remain stable and

the value of transportation (basis) rises. 

State of the Markets Report • June 2005 139

$4

$5

$6

$7

$8

$9

Jan

FebMar

Apr

May

Jun

Jul

AugSep

Oct

NovDec

Spot Price ($/MMBtu)

Henry Hub

Source: Derived from Platts data.

Fig 1: Henry Hub Prices

Natural Gas Markets National Overview

Regional Variations

Although gas prices overall increased in 2004, the differences

in price among regions remained similar (see Figure 2).

Compared with Henry Hub: 

• Prices in the Northeast were higher. This difference is

long-standing. It reflects limits on pipeline and storage

capacity. The difference is higher in the winter. 

• Prices in the West were lower. This reflects overall 

limitations in moving gas between eastern and western

halves of the continent. Western gas has been lowerpriced than eastern gas in most years—but not always.

During the western energy crisis of 2000–2001, the 

pattern reversed and western prices were higher. 

Fig 2: Locational Gas Prices 2004

Natural Gas Prices

Source: Derived from Platts data.
140 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Weather and its Effects on Consumption

Weather was mild in 2004, reducing stress on the natural gas

system. Winter of 2003–2004 was 6 percent warmer than

the previous winter, and the 2004 summer (June through

August) was the ninth coolest on record, reducing electric

demand and allowing market participants to fill storage

early. The major weather events that affected gas markets

were:

Hurricane Ivan. Ivan struck the Gulf Coast September 16,

2004, disrupting both production and pipeline transportation in the gulf. At the height of the disruption, about 6.5

billion cubic feet (Bcf) were unavailable. Of this amount,

0.6 Bcf remained off line at the end of the year. In total, Ivan

reduced U.S. gas production by 0.7 percent for 2004. The

loss of production may have been responsible for a price

surge through October.

January cold snap in New England. A short period of cold

weather hit New England on January 14–16. The cold

weather stressed both the natural gas and electric power

industries, and market participants found it difficult to coordinate their activities across the two markets (see separate

essay). Still, overall, the markets worked successfully during

the event. Both power and gas markets cleared without curtailments, and prices returned to normal levels when the

severe weather passed.

Consumption. Traditional weather-sensitive load fell for

the year by 3.9 percent for residential customers and 6.7 percent for commercial customers (see Figure 3). The decline

reflected the warmer winter (6 percent warmer than the

year before). Industrial and power generation load increased

2.2 and 4.2 percent, respectively. The increase in electric

load is particularly significant. It came despite a cool 

summer and reflected the large amount of combined-cycle

natural gas generation that has come on line in the last five

years. The increase is likely to continue, and the mild

weather may have masked its significance for the future.

Natural Gas Prices, Storage, and Oil Prices

Over time, two major factors have affected natural gas

prices: the size of storage inventories and the price of oil.

When storage is low compared with historical experience, gas

prices tend to rise, sometimes sharply. Other things being

equal, gas prices also roughly track the price of oil.

Storage Issues

Natural gas storage inventories started at low levels, but

rose rapidly through the spring (See Figure 4). Inventories

reached the highest levels ever recorded by the end of the

2004 injection season.

Storage affected gas prices most directly during the fall.

Taking advantage of a mild summer, market participants

filled storage to higher levels earlier than usual. During the

fall, before winter weather arrived, additional gas supplies

could not be forced into storage and faced relatively low

shoulder-month demand in other markets. As a result,

prices fell, then recovered as winter set in. 

Natural Gas Markets National Overview

24%

15%

35%

26%

Residential

Commercial

Industrial

Power

Generation

0

500

1,000

1,500

2,000

2,500

3,000

3,500

Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar

5-year range 2003-04

2004-05

Source: Derived from EIA Weekly Storage Report.

Fig 4: Storage Levels

Fig 3: Demand shares in 2004

Source: Derived from EIA data.
Longer-term Relationship and Oil Prices

When storage inventories are significantly lower than 

normal for a given time of year, gas prices tend to rise. This

is a market response to concerns that supplies may not be

sufficient for the coming peak season, and a resulting desire

to buy more gas to fill storage more quickly.

Storage inventories do not completely explain natural gas

prices. More recently—starting in 2004—the effects of oil

prices on gas prices have been more prominent.

Prevailing gas prices when storage is normal have risen over

the past few years. Figure 5 plots gas prices against storage

levels, with gas prices controlled for oil prices. The result

shows that the change in gas prices when there is no shortage of storage is primarily the result of rising oil prices.

State of the Markets Report • June 2005 141

Natural Gas Markets National Overview

Fig 5: Henry Hub Storage Concentration Correlated for Oil Price

0%

50%

100%

150%

200%

250%

-800 -600 -400 -200 0 200 400 600 800 1000

Deviations from 5-year Average Storage Inventories (Bcf)

Weekly Avg Ratio SPOT (NG over Crude in MMBtu)

2005, through May

1999-2003

2004

95% low

95% high

2004

2005

1999-2003

Lines calculated to encompass 95% of the 1999-

2003 data based on a logarithmic relation

Source: Derived from Platts and EIA data.
82%

15%

3%

Domestic production

Pipeline

imports

LNG

0

500

1000

1500

2000

2500

3000

3500

4000

2000 2001 2002 2003 2004

Volume (Bcf per year) 

LNG

Canadian

 Imports

Fig 7: Natural Gas Imports

142 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Natural Gas Markets National Overview

In 2004, domestic gas production declined by 1.4 percent

as output from some key traditional basins declined. Figure

6 shows the major sources of U.S. natural gas supply.

Natural gas suppliers responded to declining production and

high prices by increasing:

• Imports into the United States, both from Canada and, as

LNG, from other countries. 

• Efforts to improve traditional production.

• Deployment of technologies that were sometimes too

costly in previous years.

Imports. Canadian imports increased by 0.5 percent in 2004

to 3.2 Tcf, after a larger decrease in 2003 (see Figure 7).

Canadian imports have not recovered to levels seen in the

early 2000s. 

LNG imports rose by almost 29 percent, to 0.65 Tcf. Most

LNG imports came from Trinidad and Tobago (71 percent

– see Figure 8) and Algeria (19 percent). All of the LNG

terminals in the United States saw increased deliveries

during the year except Lake Charles, which was down for

maintenance during the last part of the year (see Table 1).

Lake Charles is also farther from load centers than the

other terminals, receives a lower netback, and is most likely to be the “swing terminal” for LNG.

Increased Drilling Activity

Natural gas producers in the United States increased their

efforts to find natural gas during 2004. Expenditures on

exploration and production rose by 11 percent over 2003, 45

percent over the average at 2001 and 2002 (see figure 9). The

number of drilling rigs dedicated to finding natural gas

increased throughout the year and averaged 15 percent higher than in 2003. This increased activity did not lead to

increased production overall—though in some basins it did

reduce or prevent declines that had been expected.

Supply Responses to High Natural Gas Prices

2003 2004

Cove Point 66.1 209.2 

Elba Island 43.9 105.3

Everett 158.3 173.7

Lake Charles 238.2 163.8

Source: Derived from EIA Natural Gas Monthly data.

Fig 6: Supply shares 2004

Source: Derived from EIA data.

Source: Derived from EIA Natural Gas Monthly data.

Table 1: LNG Deliveries
State of the Markets Report • June 2005 143

Increased Penetration of 

Unconventional Technology

Producers have turned to new production plays in recent

years to stem the decline in domestic production. These

include tight formations in Texas’ Barnett Shale, deep gas

and deepwater gas, and coalbed methane.

• Barnett Shale. The Barnett Shale is a tight formation in

Texas. During 2004, production from the Barnett Shale

increased by 22 percent, to 520 Bcf for the year. This

helped ensure that overall production in Texas grew during the year.

• Deep gas. Shallow water production in the Gulf of

Mexico has been declining rapidly since 2001 (see Figure

10). Producers responded by increasing deep drilling—

both drilling in deep water and to greater depths in shallow water. Increases in deep drilling alleviated some of

the decline in output from shallow water drilling between

2000 and 2003. Deep gas production remained constant

between 2003 and 2004.

• Coalbed methane. This technology has been in widespread use in the San Juan Basin and onshore Gulf Coast

since the early 1990s. In recent years, those sources have

declined, but a rapid increase in coalbed methane in the

Rocky Mountains has increased overall production from

this source, about 2 percent in 2004. 

Taken together, these technologies have helped slow the

decline in production in recent years. Except for the Barnett

Shale, however, increases in 2004 were marginal at best.

0

200

400

600

800

1000

1200

1400

Jan-01Jan-02Jan-03Jan-04Jan-05

Number of rigs .

0

10

20

30

40

50

60

70

E&P investment billions 

Rig count

E&P

investment

Rig count

E& P investment

Fig 9: Rig Counts and E&P Investments

10.9 10.6

8.8 8.2 7.3

2.7 3.2

3.6 3.9

3.9

0

2

4

6

8

10

12

14

16

2000 2001 2002 2003 2004

Production (Bcf/day)

Deepwater Gas

Shallow Water Gas

Fig 10: Gulf of Mexico Production

Source: Derived from Baker, Hughes, and Oil and Gas Journal data.

Source: Derived from EIA Natural Gas Monthly data.

Natural Gas Markets National Overview

Trinidad & Tobago 

71%

Algeria 

19%

Qatar 

2%

Nigeria 

2% Oman

1% Australia 

2%

Malaysia 

3%

Fig 8: 2004 LNG Source Countries

Source: Derived from EIA data.
144 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Natural Gas Markets National Overview

Infrastructure Investment

Company Project Name Docket Date Capacity Miles Hp Cost States 

MMcfd $Million

AES Ocean Express Ocean Express Pipeline CP02-90 1/29/04 842 53.6 $264.2 FL

Northwest Pipeline Corp Everett Delta Lateral Project CP01-49 2/18/04 113 9.2 $24.1 WA

Cheyenne Plains Gas Pipeline Co CP03-302 3/24/04 560 387.2 20620 $410.1 CO,KS 

TransColorado Gas Transmission Corp CP04-12 3/24/04 1125 0.1 20120 $28.6 CO

Tractebel Calypso Pipeline Calypso Pipeline Project CP01-409 3/24/04 832 41.8 $144.3 FL

Transwestern Pipeline Co San Juan Lateral Expansion CP04-104 8/5/04 375 72.6 20000 $138.4 NM

Trunkline Gas Company LNG Loop Project CP04-64 9/17/04 1500 22.8 $ 50.0 LA

Cheniere Sabine Pass Pipeline Co. CP04-38 12/21/04 2600 16 $ 90.0 LA

Table 2: Major Pipeline Projects Certificated in 2004

Source: FERC, Office of Energy Projects.

Company Project Name Docket Date Capacity Miles Hp Cost States 

MMcfd $Million

El Paso Natural Gas Company Line No. 2000 Power Up Phase I CP03-1 2/04 120 0 73720 $81.0 AZ, NM, TX

El Paso Natural Gas Company Line No. 2000 Power Up Phase II CP03-1 4/04 100 0 45000 $54.0 AZ, NM, TX

Texas Eastern Transmission LP M-1 Expansion Project CP02-381 5/04 197 32 28000 $66.0 AL, MS, TN

El Paso Natural Gas Company Line No. 2000 Power Up Phase III CP03-1 6/04 100 0 32880 $39.0 AZ, TX 

TransColorado Gas Transmission Corp CP04-12 8/04 125 0.1 20120 $28.6 CO

Texas Eastern Transmission, LP Mid-Atlantic Expansion Project CP03-43 10/04 223 35 0 $83.0 PA

ANR Pipeline Company West Leg Expansion CP02-434 10/04 220 33 0 $42.0 IL, WI

Northwest Pipeline Corp Everett Delta Lateral Project CP01-49 11/04 113 9.2 0 $24.1 WA

Cheyenne Plains Gas Pipeline Co CP03-302 12/04 560 387.2 20620 $410.1 CO, KS

Table 3: Major Pipeline Projects Completed in 2004

Source: FERC, Office of Energy Projects.

The lack of long-distance projects reflected market realities

in the industry. To justify construction of a new long-haul

pipeline, the price difference (basis) between two regions

must be high enough on average to pay for the cost of additional pipeline capacity. Figure 11 shows basis differentials

among key regions in 2004.

During 2004, the natural gas industry continued to invest in

upgrading its infrastructure for transmission and storage.

Total investment in interstate pipeline transportation projects that came on line in 2004 was $2.18 billion, compared

with $3.75 billion in 2003 (EIA). Completion of the Kern

River expansion in 2003 ($1.26 billion) represents most of

the difference. Most of the new construction went to

strengthen the existing grid, and there were few major longdistance projects. Investment in storage fell to $159 million

in 2004 from $253 million in 2003. 
State of the Markets Report • June 2005 145

Natural Gas Markets National Overview

The largest basis differentials were between producing areas

and the Northeast (Transco Zone 6–New York). Although

the basis was high for short periods in the winter, it was low

for most of the year. Averaged across the year, the basis to

the Northeast was about equal to current pipeline tariffs.

The tariffs, however, represent cost-of-service rates for

pipelines that companies built in the past and have depreciated. The tariff rate is likely to be high enough to justify

some incremental upgrades (for example, compression,

when possible) but not to pay for more costly expansions. In

addition, it may be less costly to develop or increase LNG

terminal capacity.

The 2004 basis from Opal (in Wyoming) to California was

about the same as from the San Juan Basin. This represented a major change from 2002 when there was not enough

pipeline capacity and much Wyoming gas was trapped locally and sold at lower prices than other western gas. In 2003,

Kern River opened its expansion to California, removing

the bottleneck and allowing Wyoming gas to receive prices

prevailing in the West. 

Overall, gas infrastructure investment in North America has

been an important market success story for many years.

Over time, natural gas supplies have constantly shifted, as

have markets. Companies have sponsored and built

pipelines to meet the changing needs so that market dislocations, like the Wyoming production pocket, have generally

been short-lived.

-2

-1

0

1

2

3

4

5

6

$/MMBtu

Henry Hub 

to Chicago

Henry Hub to 

Columbia Appalachia

Henry Hub to 

New York

Rockies to 

California

El Paso San 

Juan to 

California

Henry Hub to 

California

Dashed lines separate each route. 

Each vertical bar represents 1 month, 

January 2004 to December 2004.

Fig 11: Monthly Basis Differentials for Major Transport Routes

Source: Derived from Platts data.
146 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Natural Gas Markets National Overview

Financial Gas Market Growth

Financial services available to the natural gas industry

increased in 2004. These improvements included both new

financial products (swaps, for example) and more widely

used clearing services.

New Products 

Financial natural gas markets have been growing in importance since 1990, and new financial products have recently

become available to customers. Nymex added a wide range

of financial natural gas products to its electronic ClearPort

trading system. All of the products settle financially; there

is no physical delivery. The products offer natural gas buyers and sellers a variety of tools to hedge many different

price risks. These and similar products are also available on

the IntercontinentalExchange (ICE) and through voice

brokers and bilateral contacts. The Nymex listing makes

them easier to trade, and gives daily published settlement

prices for the contracts with open interest. In 2004,

Nymex’s new natural gas products included:

Basis swaps. These products let market participants hedge

the basis difference from Henry Hub to a given location for

some time in the future. For example, a buyer could lock in

a basis difference between the Henry Hub and Transco Zone

6–New York for the month of January. Such a buyer would

no longer be vulnerable to changes in the basis value

between New York and the Gulf Coast for that month. Basis

swaps give market participants price discovery at points

other than Henry Hub. Nymex offered 12 additional delivery points for basis swaps in 2004 (in addition to 29 pre-existing points).1

Index and swing swaps. Index swaps let a market participant hedge exposure to daily price changes by locking in a

monthly index at a given physical point. Swing swaps let

customers hedge against changes in daily price changes,

without being tied to a monthly index. Both products are

hedges against daily price volatility. Nymex added six locations for index swaps and daily swing futures.2

Penultimate swapsare the purchase or sale of a fixed quantity at a fixed price in exchange for the settlement price of

the underlying futures contract on the day prior to its expiration. They protect customers against last-day changes in

futures prices. Nymex added this product for its basic natural gas futures contract.

Calendar spread options are options on the price spread

between two specified months. Market participants can use

calendar spread options to hedge the value of storage.

Nymex added spread options between the months of April

and October and the months of October and January,

Taken together, this array of hedging tools gives customers

great latitude to shape their risk management strategies. To

the extent that the hedging instruments trade in a liquid

market, market participants can adjust their risk management strategies as needed. 

Clearing Services 

Clearing services enhance the liquidity of markets by giving customers a convenient way to address credit risk and

to net credit exposures. During 2004, both ICE and

Nymex saw the volumes in their clearing services rise rapidly. For ICE, the volumes increased almost four fold,

from 4.5 million contracts to 17.0 million contracts. (Each

contract covers 2,500 MMBtu). For Nymex, clearing volumes for both swaps and options increased more than five

fold, from 2.4 million contracts to 13.4 million contracts.

Overall

Development of these financial products represents significant innovation for the industry. Their demonstrated

market viability shows that customers are using the services. Together the innovation and market diffusion of these

services indicates a healthy market. Customers have more

risk management options, which is important in an industry with high capital costs and volatile prices. They also

see a market that can create services (like clearing) that can

be used to respond to problems that would otherwise

undermine liquidity.
State of the Markets Report • June 2005 147

Natural Gas Markets National Overview

Information Issues Remained Important

Natural gas markets depend on having reliable information

about prices and basic demand and supply conditions.

Price Indices

Participation in gas price indices increased in 2004, signalling increased confidence. During the early years of the

decade, some market participants manipulated the price

indices that many participants use for basic price discovery

and often include in contractual pricing terms. 

During 2003 and 2004, the Commission encouraged the

industry to improve index reporting. By 2004, companies

reporting to the index publishers had better procedures for

ensuring honest reports. The index publishers reported far

more details (such as the number of transactions and total

volumes being reported for a given price). The Commission

issued a rule laying out requirements for indexes referenced

in contracts under the Commission’s jurisdiction. By 2004,

many market participants expressed greater confidence in

using the indexes. 

Nonetheless, popular confidence in natural gas pricing

remains uncertain. With rapid price increases in 2003 and

2004, pricing mechanisms remain under close scrutiny by

policy makers in Congress and elsewhere. 

EIA Storage Report

Basic information about supply and demand remained

scarce, so that EIA’s weekly storage reports retained disproportionate influence over the market. The United States has

no timely and reliable reports on current gas production. As

a result, EIA’s storage estimate has become the most available indicator of the overall balance of supply and demand—

despite the fact that it represents a tiny proportion of gas

being produced or consumed at any given time. 

Late in November, one company’s clerical error led EIA to

underestimate storage injections for the previous week.

During the rest of the trading day, gas prices rose by 15 percent. Because the reporting also happened to be the close for

the Nymex December futures contract and for bid week for

monthly physical deliveries in December, the overall effects

on the market were large.

In the absence of better information on supply, natural gas

markets will remain vulnerable to errors or aberrations in

the few reports that are available.
148 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Natural Gas Markets National Overview

The natural gas industry faced a declining traditional

resource base in 2004, at the same time that gas usage in electric generation increased. Mild weather helped avert any

significant disruptions, and natural gas markets responded

largely as expected. Tight supplies (and rising oil prices) led

to higher gas prices. In turn, the industry increased gas

imports from Canada and, as LNG, from other countries;

increased drilling for new reserves; and increased efforts to

produce natural gas from less traditional supply sources,

such as tight formations. Nonetheless, overall supply

remained about the same.

Going forward, the natural gas industry faces several crucial

market questions including:

How will gas markets respond to more severe weather? In

2004, natural gas supply and demand balanced closely, largely because of a decline in residential and commercial

demand occasioned by relatively mild weather. More severe

weather would impose significantly greater stresses on the

natural gas system, leading at least to higher prices. 

A shift in demand for gas is likely to exacerbate any weather-related problems. Price spikes occur because many or

most customers are unwilling or unable to reduce their

demand. Traditional industrial demand served to limit the

severity of natural gas price spikes because customers bought

less gas if the price went too high. In today’s natural gas

industry, the electric generation sector is growing most rapidly. Its demand for gas tends to be unusually inelastic

because there is little price-responsive demand for electric

power. As a result, electric demand is unlikely to serve as the

same sort of shock absorber for severe weather as traditional industrial demand. 

Will innovations help improve natural gas supplies? One

response to high prices is to devote resources to finding and

deploying new approaches. In natural gas, current high

prices have led the industry to work at developing some less

conventional supply sources, to limited effect so far. More

changes are likely. For example, early in 2005, EnergyBridge

introduced an LNG tanker with onboard liquefaction. Such

a ship takes significantly longer to offload than LNG tankers

at terminals, but incurs much less capital cost (and environmental dispute), and so can deliver gas more flexibly to more

points. The first deliveries were to the Gulf Coast, but proposals are already on the table for two potential delivery

points in New England, and such technology could eventually help a company arbitrage gas prices in widely dispersed

areas. 

How will global markets for natural gas develop? The

United States has long experience with spot markets for natural gas that allow arbitrage among different parts of the

grid. The beginning of 2005 saw early signs that a North

Atlantic spot market is developing between the United

States and Western Europe, especially Great Britain. British

gas prices spiked in late January and February (see Figure 12)

in response to cold weather. Simultaneously, Spain was

short of gas to fuel combined-cycle electric generation. LNG

deliveries to Lake Charles stopped, and there were reports

that shippers diverted cargos destined for the United States

to Europe. (Shippers have diverted some cargos from

Europe to the United States for several years.) 

Development of more flexible North Atlantic LNG deliveries could have significant effects for both Europe and North

America in the future—mostly positive ones, because gas

will flow to areas with the greatest willingness to pay, which 

probably correspond to the areas with the greatest need. 

Source: Derived from Bloomberg and U.S. Waterborne LNG data.

Fig 12: Henry Hub and European Gas Prices

$0

$5

$10

$15

$20

$25

1/3/05

1/10/05

1/17/05

1/24/05

1/31/05

2/7/05

2/14/052/21/05

2/28/05

3/7/05

3/14/053/21/053/28/05

4/4/05

4/11/054/18/05

4/25/05

5/2/055/9/05

5/16/05

Price ($/MMBtu)

Henry Hub

UK NBP

Deliveries to 

Lake Charles

U.K. Spot Gas Price

Henry Hub

Conclusion
State of the Markets Report • June 2005 149

Natural Gas Markets National Overview

Market Profiles

The first profile is on trading (especially financial) at the

Henry Hub, because the Henry Hub market forms the basis

that market participants use to measure all other natural gas

markets. The regional profiles cover five regions:

Northeast, Southeast, Midwest, South Central, and the

West. Each regional profile can stand alone as a summary of

the region’s natural gas markets in 2004. The profiles are as

standard as possible but vary somewhat because of differences in the nature of the regions themselves. The regional

profiles generally include the following sections:

Market Description. The opening section of each profile

includes:

• A brief description of the region and important 

factors affecting its natural gas market,

• A map with average prices for 2004 for available 

pricing points and key entry or exit points for natural

gas supply,

• A summary price table, 

• A brief description of major issues that affected the

region in 2004,

• Overall statistics for supply and demand.

Spot Market Prices and Volumes. This section includes:

• A graph of daily prices for major pricing points during

the year. It is especially useful for identifying price

spikes and seeing the overall range and volatility of

prices through the year. Basis values for the region

(differences in prices between key regional points and

the Henry Hub), are included where relevant.

• Forward prices and volumes traded, as reported several times during the year. This information shows

how trader expectations of coming seasonal prices

evolved during the year.

• Volumes traded, as reported by ICE and Gas Daily. 

Infrastructure Development. This section contains a table

of major construction projects for pipelines, storage, and

LNG in the region. The table includes information on the

size, cost, location, and status of each project.

Regional Gas Supply. This section describes where the gas

comes from to serve a given region. This source information

includes local production, but in most consuming regions,

the bulk of supply comes from outside by pipeline or from

LNG terminals. The section also describes gas storage facilities and usage in the region, because these can supply winter

or peaking demand.

Regional Market Shares. This section shows the relative

market shares for capacity of the major pipeline companies

that serve a region. It also shows the largest holders of

pipeline capacity rights, usually large downstream customers. 

Selected Topics. Each regional profile includes at least one

short article that highlights an important event or development during the year in greater detail than is possible in the

standard sections.
150 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Natural Gas Markets National Overview

1 New points include ANR Pipeline Louisiana, Upper Midwest,

(Dawn, Ontario), Florida Gas Transmission—Zone 3, East Texas,

Katy, Kern River Gas Transmission—Wyoming, Niagara, Questar

Pipeline—Rocky Mountains, Tennessee Gas—Louisiana,

Tennessee Gas—Zone 0, Texas Gas— Zone SL, Trunkline Gas—

Louisiana, and Williams Gas Central (Texas, Oklahoma, and

Kansas).

2 New swap locations include Henry Hub, Houston Ship Channel,

Panhandle Eastern—Texas, Oklahoma, El Paso—Permian Basin,

Waha, and Chicago citygates.

Disclaimer: This report contains analyses, presentations, and 

conclusions that may be based on or derived from the data sources

cited, but do not necessarily reflect the positions or recommendations

of the data providers. 

Endnotes
Henry Hub, La., serves as the primary U.S. pricing 

reference point for buying and selling natural gas because

it is the delivery point for the New York Mercantile Exchange

(Nymex) natural gas futures contract.1 Nymex chose Henry

Hub about 15 years ago because it connects with nine interstate

and four intrastate pipelines with access to markets in the Gulf

Coast, Southeast, Northeast, and Midwest.2 Consequently,

Henry Hub serves as the key link between natural gas financial

and physical markets. Market participants in these regions and

across the United States can price their physical and financial

natural gas contracts based on the price of the Henry Hub

futures contract, plus or minus a differential to their delivery

points. 

Futures contracts constitute the purchase or sale of a standardized product—set volume, delivery location, delivery period—

with the obligation to take or make delivery. Some futures contracts do not extend to physical delivery and include a specified

financial settlement. The specifications for the Nymex Henry

Hub natural gas futures contract are for physical delivery,

unless the original contract purchased or sold is sold or bought

back prior to the contract’s expiration. Nevertheless, the

majority of Henry Hub natural gas futures do not go to delivery

because in a straightforward strategy (hedge or speculation),

buyers sell contracts and sellers buy them prior to expiration to

keep the effects financial rather then physical.

Futures contracts serve two primary purposes: 

• As a pricing mechanism for purchases and sales of a given

contract’s underlying physical commodities in order to

hedge against price changes.

• As a means of price discovery. 

Published prices for a natural gas contract occur via daily settlement by Nymex for 72 consecutive forward months and

through monthly futures expiration prices. On the third business day prior to the end of each month, trading stops for the

prompt month natural gas futures contract (the first forwardmonth traded), and the contract expires. Physical natural gas

contracts often use the natural gas futures expiration price in

their pricing terms. The expiration price also provides a reference point for physical trading during the natural gas market’s

bidweek, when the next month’s physical transactions are commonly transacted.

In 2004, Henry Hub futures prices reached the highest average

nominal levels since natural gas futures trading began in 1990.

Natural gas futures prices for the prompt month settled on a

Natural Gas Trading

State of the Markets Report • June 2005 151

2004 Futures Settlement Prices

$0

$1

$2

$3

$4

$5

$6

$7

$8

$9

$10

/05/04/26/04/16/04/08/04/29/04/19/04/10/04/31/04/21/04/12/04/02/04/23/04/13/04/04/04/25/04/15/04/06/04/27/04

 ($ per MMBtu)

Daily Futures Settlement Price

Average Daily Futures Settlement Price for 2004

Futures Expiration Prices

Source: Derived from Platts Gas Daily data.

Year Avg Daily Futures Percent Change

Settlement Price from Prior Year

1995 $1.688

1996 $2.506 44%

1997 $2.476 -1%

1998 $2.158 -13%

1999 $2.320 8%

2000 $4.315 86%

2001 $4.054 -6%

2002 $3.367 -17%

2003 $5.492 63%

2004 $6.177 12%

Source: Derived from Bloomberg and Platts Gas Daily data.

Henry Hub Prices ($ per MMBtu)
152 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Forward futures settlement prices are shown going 3 years

beyond the prompt month as of the end of each quarter during

2004. At the end of the first three quarters of the year, the market expressed concern over natural gas prices for the winter of

2004–2005. As the figure shows, the shape of the forward

curve—higher prices for the coming winter, as compared with

the subsequent two winters (referred to as “backwardation”)—

conveyed market expectations that the supply-demand balance

would be tight and that winter weather would be cold in

2004–2005. Backwardation expressed expected price relief later.

High price expectations are most apparent in the forward curve

at the end of the third quarter 2004. By the end of the year,

when part of the heating season was already over, the market

adjusted its views, and the price curve for the balance of the

winter season, February to March, declined from the third

quarter.

Natural Gas Trading

Forward Futures Settlement Prices

$0

$1

$2

$3

$4

$5

$6

$7

$8

$9

May

Aug

Nov

Feb

May

AugNov

Feb

May

AugNov

Feb

May

AugNov

($ per MMBtu)

1. First Quarter, March 31: Lowest prices of year

2. Second Quarter, June 30: Elevated prices from 1st quarter

3. Third Quarter, September 30: Highest prices in front months

4. Fourth Quarter, December 31: Lower prices in front months, continued

stronger prices going into following winters

1

2

3

4

Fundamental market factors influenced both natural gas

physical prices and financial product prices during the latter

part of 2004.

Production curtailments related to Hurricane Ivan. In

mid-September 2004, Hurricane Ivan caused a reduction in

natural gas supply from the Gulf of Mexico. Natural gas

production saw peak shut-ins of 6.5 Bcfd,8 greater than

expected damage to platforms, and extended curtailments

through the balance of 2004. In reaction to this hurricane,

next-day Henry Hub physical prices and futures prices for

the prompt month, which had been declining into the mid-

$4.50s per MMBtu (the low prices for the year), rose

sharply to over $6.00 per MMBtu by the end of September.

Crude oil market strength. From January through July

2004, crude oil futures traded, on average, below $40 per

barrel. In August, prices began to increase steadily to reach

a high settlement price for the year of $55.17 per barrel in

late October. The continued strength of crude oil prices

supported the natural gas futures market and also contributed to natural gas volatility.

Actual and expected winter weather. By early November,

natural gas prices held firm in response to the extended

effects of Hurricane Ivan and a strong crude oil market.

Thus when certain sections of the country experienced

early winter weather, prices moved upward. The next-day

Henry Hub physical price increased almost $1.00 per

MMBtu to trade above $7.00 per MMBtu from late October

to early November. Actual and expected winter weather

pushed the futures market even higher with prices above

$8.00 per MMBtu.

Storage reporting issues during late November (for

December delivery). On November 24, the Energy

Information Administration (EIA) issued its natural gas storage report for the week ending November 19. The report indicated a withdrawal of 49 Bcf, in sharp contrast to market expectations, which were in the 13–25 Bcf range. The same day

(November 24) marked the expiration of the December 2004

futures contracts, when futures prices settled up by $1.183 per

MMBtu to $7.976 per MMBtu. The following week, EIA issued

a 32 Bcf correction to the prior week’s storage report.

Commission staff issued its final report on this matter in

February 2005.9

Factors Affecting Henry Hub Physical and Financial Trading in the Fourth Quarter

daily average of $6.177 per MMBtu for 2004, an increase of

12.5% from 2003 in contrast to next-day Henry Hub physical

prices which increased by 7%. For January through August,

prompt-month futures traded in a range between $5.00 and

$7.00 per MMBtu. Starting in September, next-day Henry Hub

physical prices and prompt-month futures prices rose steadily

from the sub $5.00 per MMBtu level (low futures price of $4.57

per MMBtu on September 10) to above $8.00 per MMBtu range

(high futures price of $8.75 per MMBtu on November 3). 

Source: Derived from Platts Gas Daily data.
Henry Hub natural gas futures volume traded for 2004 dropped

for the second year in a row, but was higher than average volume traded over the past 10 years. Volume is the total number

of contracts traded for a single time period, such as daily volume or monthly volume. It also can be measured in volumetric

units. Despite the higher price levels and news articles suggesting the entrance of new participants into the natural gas market, the natural gas futures contract did not set any volume

records, unlike the crude oil futures contract. The total natural

gas futures volume traded in 2004 amounted to 17.4 million

contracts,2 which was lower than it had been during the prior 2

years. Total monthly volume and end-of-month open interest

for 2004 are shown. The largest natural gas futures volume

transacted for the year occurred during September, due in part

to the active hurricane season.

Open interest is the total number of outstanding contracts

where an offsetting sale (or purchase) has not been made; it is

indicative of future activity in the contract. Futures open interest of the noncommercial sector by net long (purchases) and net

short (sales) position are delineated in relation to the futures

settlement price (see figure). Noncommercials are trading entities that do not use the futures contract to hedge their business activities;3 they are commonly referred to as speculators. Traders in the noncommercial classification include

hedge funds, also known as managed money traders.4

Open interest in 2004 provides some evidence to support

the widespread observation that financial players have

become more active in natural gas markets. Another category of noncommercial futures open interest is known as

“spreading open interest.” Spreading indicates the extent

to which the trading entity holds equal long and short positions for the same commodity, but for different time periods. For example, an entity might be long for January and

short for February, in which case, it would benefit if the

January price rose compared to the February price (i.e., the

“spread” between the months changed). A company with

a large spreading open interest is betting that the difference

between two time periods will change, not that forward

prices will generally go up or down.

State of the Markets Report • June 2005 153

FINANCIAL MARKETS: FUTURES VOLUMES

Natural Gas Trading

Henry Hub 10-Year Annual Trading Volume

0

50,000

100,000

150,000

200,000

250,000

1995 1996 1997 1998 1999 200 2001 2002 2003 2004

Bcf

Monthly Volume and Open Interest

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

Jan Feb Mar Apr May Jun Jul Aug Sept Oct Nov Dec

Volume and Open Interest (Bcf)

Volume

Open Interest

Source: Derived from Nymex data. Source: Derived from Nymex data.

-500

-400

-300

-200

-100

0

100

200

300

01/06/0401/27/0402/17/0403/09/04

03/30/04

04/20/0405/11/04

06/01/0406/22/0407/13/0408/03/04

08/24/04

09/14/0410/05/04

10/26/0411/16/0412/07/04

12/28/04

Open Interest (1,000,000 MMBtu)

$0

$1

$2

$3

$4

$5

$6

$7

$8

$9

Futures Settlement Price ($ per MMBtu)

Noncommercial Net Volume

Nymex Settlement Price

Non-Commercial 

Net Open Interest

Natural Gas Futures 

Settlement Prices on 

Commitment of Trader 

Report Dates

Source: Derived from Platts Gas Daily, and CFTC’s Commitment of Traders Report data.

Noncommercial Net Open Interest
154 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Natural Gas Trading

Spreading open interest for noncommercials increased

over 2004, both in absolute volume and as a percent of

total open interest. From the beginning of the year to its

end, spreading open interest increased almost 125 percent

from just under 500 Bcf to over one trillion cubic feet or

almost 27 percent of open interest. The noncommercial

spreading open interest for 2004 exceeded all prior years

for the natural gas futures contract.

Both Nymex and the Commodities Futures Trading

Commission (CFTC) examined open interest in 2004 to

determine if the noncommercial sector, specifically hedge

funds, created greater price volatility.5 Recent anecdotal

evidence points to the evolving interest of hedge funds in

the energy sector. Prior to 2004, hedge funds traded energy products. During the past year, there were reports of

significant new hedge fund entry into the energy trading

space. In 2004, Utilipoint International Inc. identified

300 energy-focused hedge funds.6 The FERC Office of

Market Oversight and Investigations cannot verify the

exact number of hedge funds trading natural gas and other

energy commodities.

0

200

400

600

800

1,000

1,200

01/06/04

01/27/04

02/17/04

03/09/0403/30/04

04/20/04

05/11/04

06/01/04

06/22/0407/13/04

08/03/04

08/24/04

09/14/04

10/05/0410/26/04

11/16/04

12/07/04

12/28/04

Open Interest (Bcf)

0.00%

5.00%

10.00%

15.00%

20.00%

25.00%

30.00%

Percent of Open Interest

Noncommercial Futures Spreading Positions

Percent of Open Interest

Spreading Open Interest in Gas Futures

Source: Derived from CFTC’s Commitment of Traders Report data.

FINANCIAL MARKETS: HISTORICAL VOLATILITY

0%

20%

40%

60%

80%

100%

120%

Jan

FebMarMar

Apr

May

Jun

Jul

AugSep

Oct

Nov

Dec

20-Day Historical Volatility for 2004 Avg. 20-Day Historical Volatility for 2004

Avg. 20-Day Historical Volatility for 2003 Avg. 20-Day Historical Volatility for 2002

Avg. 20-Day Historical Volatility for 2001

Source: Derived from Platts Gas Daily data.

Historical volatility, as measured using futures settlement

prices, was lower than it had been over the previous 3

years. Historical volatility is the annualized standard

deviation of past price changes measured in percentage

terms. The measurement of historical volatility shows

what actually happened in the market as opposed to what

is expected to occur in the future. Historical volatility

measures the degree to which the market price moved up

and down, and disregards the absolute price levels.

Compared with the 2004 average, volatility was higher

during two periods: winter 2003–2004, specifically

January; and the onset of winter 2004–2005, specifically

the fourth quarter of 2004. 

20 Day Historical Volatility
Physical trading of natural gas is related to financial trading for 

several reasons: 

• Fundamental factors that influence the physical market, such

as weather, supply, and demand, also affect financial product

prices. 

• Many physical purchase and sale contracts have pricing terms

based on financial prices, the most prominent being the

monthly Nymex natural gas futures expiration price.

Correspondingly, many financial purchase and sales contracts

have financial settlements linked to the physical monthly and

daily indices. For example, monthly physical indices form

part of the financial basis swap settlements.

• Nymex’s natural gas futures contract has a physical delivery

mechanism. If a market participant does not close out an

open futures contract, then the participant must make or take

delivery of the natural gas product at Henry Hub. The delivery mechanism helps to ensure that physical and futures

prices converge at futures expiration. When physical and

futures prices do not converge, market participants trade various physical and financial products in order to arbitrage the

difference in the prices.

Physical natural gas trading experienced two trends in 2004: divergence of physical and financial prices at Henry Hub, and a rise in

next-day Henry Hub physical volumes.

For most of the year, even during a period of relatively high

volatility in January, the next-day physical prices at Henry Hub

and the futures prompt-month prices corresponded closely. From

January through September, an average difference of -$0.08 per

MMBtu existed between next-day physical prices at Henry Hub

and futures prompt-month settlement prices.7 From October

through December, the average difference jumped to -$.89 per

MMBtu (see figure). Futures for most of the fourth quarter were

trading at a premium to the next-day prices at Henry Hub. The

difference between the prices was the largest average for a fourth

quarter. The physical market may have been reacting to shortterm, then-current fundamentals, such as weather that was not as

cold as expected. The futures market was looking forward toward

broader winter expectations.

State of the Markets Report • June 2005 155

Natural Gas Trading

In addition to natural gas futures, other products were available

to hedge natural gas prices during 2004. Basis swaps hedge the

pricing differential between Henry Hub and specified delivery

points. Basis swaps can have a physical or a financial settlement.

Financial basis swaps settle on the difference between a monthly physical index and the Nymex expiration price. Trading for

basis swaps takes place on a variety of platforms, including

Nymex and IntercontinentalExchange (ICE), and through

voice brokers and direct bilateral transactions. Financial basis

swaps price on Nymex are shown for four select points over

2004; the prices are for the prompt month (see figure). 

OTHER FINANCIAL PRODUCTS

PHYSICAL TRADING

Swap Prices

-$2.0

-$1.5

-$1.0

-$0.5

$0.0

$0.5

$1.0

$1.5

$2.0

$2.5

$3.0

$3.5

$4.0

$4.5

$5.0

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

NovDec

($ per MMBtu)

Chicago citygates

Houston Ship Channel

SoCal

Transco Zone 6 - New York

Source for chart at right: Derived from Bloomberg L.L.C data.

Next-Day Henry Hub Physical Prices

-$4

-$3

-$2

-$1

$0

$1

$2

$3

$4

$5

$6

$7

$8

$9

$10

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Price ($ per MMBtu)

Futures Settlement

Next-Day Henry Hub,

Difference: Cash less futures

Gas Daily 

Source: Derived from Platts data.
Next-Day Henry Hub Physical Volumes

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

01/05/2004

02/05/2004

03/05/2004

04/05/2004

05/05/200406/05/200407/05/200408/05/2004

09/05/2004

10/05/2004

11/05/2004

12/05/2004

 (1,000 MMBtu)

Volume

Avg volume Jan-Sept

Avg volume Oct-Dec

Source: Derived from ICE data.

156 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Natural Gas Trading

1 For specifications for the natural gas futures contract, see

www.nymex.com. 

2 One futures contract is equivalent to 10,000 MMBtu.

3 CFTC, “The Commitments of Traders Report” CFTC Backgrounders

Number 4-91, July 2004. See http://www.cftc.gov/opa/backgrounder/opacot596.htm.

4 Haigh, Michael S., Hranaiova, Jana, and Overdahl, James A.,

“Price Dynamics, Price Discovery and Large Futures Trader

Interactions in the Energy Comples,” Office of the Chief

Economist, CFTC. See http://www.cftc.gov

/files/opa/press05/opacftc-managed-money-trader-study.pdf.

5 A Nymex March 2005 report, entitled “A Review of Recent Hedge

Fund Participation in NYMEX Natural Gas and Crude Oil Futures

Markets,” states that hedge funds comprised 9.05% of trading

volume and 20.4% of open interest for January through August

2004. A CFTC April 2005 report, entitled “Price Dynamics, Price

Discovery and Large Futures Trader Interactions in the Energy

Complex,” examines open interest for August 2003 through

August 2004.

6 “Energy Comes into Focus for Hedge Funds,” UtiliPoint

International Inc., Analysts Corner, December 17, 2004,

www.globalchange.com/articles/IA_December_17_2004_

Reprint.pdf.

7 The 2004 fourth-quarter difference between next-day physical

prices at Henry Hub and futures prompt-month settlement compares to a more narrow difference in 2003. The difference for

October through December 2003 was -$0.339 per MMBtu.

8 Minerals Management Service, Hurricane Ivan evacuation and

production shut-in statistics as of Friday, September 16, 2004.

9 Summary of the FERC OMOI investigation of events related to the

EIA Weekly Natural Gas Storage Report for November 24, 2004,

http://www.ferc.gov/whats-new/hd-current/02-10-05.asp.

Disclaimer: This report contains analyses, presentations, and 

conclusions that may be based on or derived from the data sources

cited, but do not necessarily reflect the positions or recommendations of the data providers. 

Endnotes

Monthly physical indices at Henry Hub and the

futures expiration price for 2004 settled at almost the

same prices for most of 2004, the exception being for

December when prices did not converge. From

January through November 2004, there was an average

difference of $0.006 between the monthly Platts Gas

Daily Henry Hub index and the futures expiration

price. In December 2004, a difference of -$0.196 per

MMBtu occurred. This was the same bidweek when

the EIA storage misreporting error of 32 Bcf occurred.

Volumes transacted for Henry Hub next-day physical

rose during the fourth quarter of 2004. From January

through September, total volume transacted per day

averaged 500,000 MMBtu on ICE. (ICE volumes represent sell-side only.) From October through December,

average total volume per day doubled to 1,006,000

MMBtu (see figure). The 2004 volumes are in relation

to an average volume of 604,000 MMBtu on ICE 

during 2003. 
The Midwest market1 has access to natural gas supply

from throughout North America—British Columbia,

the Western Canadian Sedimentary Basin, Appalachia, the

Midcontinent, the Gulf Coast, and the Rocky Mountains.

Regional natural gas production declined 2%, or by 14 Bcf

in 2004. In 2004, the Midwest consumed 27% of total

Lower 48 natural gas production, while accounting for 3%

of total Lower 48 gas production. Imports to the region are

critical. Estimated net Midwest imports of Canadian gas

averaged 2.3 Bcfd.2 Estimated net inter-regional firm gas

interstate gas pipeline deliveries into the Midwest totaled

3.1 Tcf, or nearly 152 Bcfd. 

The region had the highest share of residential and commercial gas use (57%).3 Gas-fired power generators consumed 5% of gas in the Midwest in 2004, the least of any

region, because of the large base of coal-fired power generating capacity. Approximately 4 Tcf of mostly underground,

market-area storage supplements long-haul pipe deliveries

during peak periods. Midwest market hubs at Chicago and

Dawn linked gas resources from multiple production basins

throughout North America to customers in eastern Canada

and northeast United States.

Midwest Natural Gas Market Profile

State of the Markets Report • June 2005 157

• Higher hub prices. Annual 

gas price differences between

Louisiana’s Henry Hub and

Chicago averaged less than

1¢/MMBtu because of 

continued excess pipeline

capacity. Prices at Alberta’s

AECO-C Hub4 mirrored gas

price increases at Henry Hub;

both were up 7%.

• Varied load factors. Load 

factors on pipelines delivering

gas from the Gulf Coast 

averaged 55%; load factors

on pipelines delivering gas

into the Midwest from 

western Canada and the

Rocky Mountains generally

exceeded 80%.

• Successful sales of capacity

rights. Several Midwest gas

pipelines vulnerable to firm

contract expirations—Natural

Gas Pipeline Co. of America

(NGPL), Northern Border

Pipeline, and Viking Gas

Transmission—were successful, at least temporarily, in 

selling expiring firm capacity

rights to various customers

into 2005.

• Lower gas consumption.

Estimated Midwest gas 

consumption declined 155 Bcf

(3%) because of mild weather

and higher natural gas prices

that were up by 7%.

Source: Derived from Platts data.

2004 Average Daily Hub Prices ($ per MMBtu)

Focal Points for 2004

2003 2004 5-Year

ANR ML7 $5.56 $5.91 $4.74

Chicago Citygates $5.55 $5.85 $4.64

Dawn, Ontario $5.78 $6.08 $4.74

Mich Consolidated Citygate $5.68 $6.00 $4.70

Northern, Demarc $5.28 $5.54 $4.44

Northern, Ventura $5.32 $5.58 $4.45

AECO-C $4.71 $5.04 $3.93

Emerson Viking GL $5.20 $5.56 $4.20

Source: Derived from Platts data.

Hub Prices ($ per MMBtu)
158 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Midwest Natural Gas Market Profile

Annual spot gas prices at key Midwest trading points—the Chicago

citygates, Dawn,5 and Michigan Consolidated Gas Co.6 citygate—

averaged $5.98/MMBtu in 2004, approximately $0.30/MMBtu

higher than 2003 prices. During 2004, daily prices at these points

ranged between $4.36/MMBtu and $8.25/MMBtu. Chicago gas

typically traded lower than MichCon (by $0.08/MMBtu) and

Dawn prices (by $0.23/MMBtu). The basis between the Henry

Hub and Chicago averaged less than $0.01/MMBtu in 2004 because

of excess regional pipeline capacity and mild weather. In fact,

Chicago gas was less expensive than gas at the Henry Hub throughout much of June, July, September, and October. For the first time,

AECO gas prices averaged more than $5.00/MMBtu (U.S.) in 2004.

The basis between AECO and Midwest market points varied

between $0.94/MMBtu for downstream points (Chicago, Dawn,

and Michigan) and about $0.50/MMBtu for more upstream

Midwest points (Demarcation and Ventura).

SPOT MARKETS: PRICES AND VOLUMES

Day-Ahead Spot Prices Monthly Average Basis Value to Henry Hub

Source: Derived from Platts data. See source note 1. Source: Derived from Platts data. See source note 2.

Supply Disposition 2004 2003

(Bcf) (Bcf)

Total Dry Production 585 599

Production by Region

Michigan 186 195

Williston Basin 41 41

Other 358 363

Other Sources of Supply (2004 Bcf)

International Supply

Imports Exports Net Imports

Canada 3,145 2,310 835

Mexico 0 0 0

LNG 0 0 0

Total 3,145 2,310 835

Interregional Pipeline Flows Net Imports

to Northeast (1,366)

to Southeast 2,535

to South Central 1,706

to West 397

Total 3,272

Demand Disposition 2004 2003

(Bcf) (Bcf)

Residential 1,871 1,990

Commercial 1,034 1,078

Industrial 1,638 1,618

Power 257 260

Losses and Other 288 297

Total 5,088 5,243

Key End Use Markets

West Central - IA,NE,SD,MN,MO,ND 1,082 1,106

Upper Midwest - MI,WI,IL,IN 2,820 2,909

Ohio Valley - OH,WV,KY 1,185 1,227

Midwest Supply Demand Statistics

Source: Derived from Bentek Energy, LLC data. Note: Negative net imports are net

exports.
State of the Markets Report • June 2005 159

Midwest Natural Gas Market Profile

Expectations for end-of-year (November and December) basis

swaps in the Chicago market were consistent throughout much of

2004. Through September, swap transactions reported by New

York Mercantile Exchange’s (Nymex) ClearPort indicated narrow

trading ranges for basis between Henry Hub and Chicago—just

$0.02–$0.05/MMBtu for November and $0.08–$0.13/MMBtu for

December. Except in October, actual basis values for the Chicago

citygate point approximated average forward expectations. The

Henry Hub futures price increased from $5.11/MMBtu in midSeptember (for October delivery) to $8.40/MMBtu by the end of

October (for November delivery) because of gas production shortfalls in the Hurricane Ivan aftermath and an escalation in crude

oil prices. As a result, the Henry Hub price rose significantly in

relation to the Chicago price, leading to a negative $0.23/MMBtu

basis in November.

The monthly volume of financial basis swaps for the Chicago

market gas traded between 20 and 40 million MMBtu on

IntercontinentalExchange (ICE) and Nymex ClearPort. Physical

market trades reported on ICE accounted for 20%–35% of financial product volume.7

FINANCIAL MARKETS: PRICES AND VOLUMES

Chicago Citygate Swaps Prices from Trade Date Chicago Citygates Forward and Swaps Volume

Source: Derived from Bloomberg L.P. and Nymex data. See source note 3. Source: Derived from ICE, Bloomberg, L.P. and Nymex data. 

Daily gas trading at Midwest hubs was mixed in 2004. During

2004, Chicago citygate trading averaged between 579,000 MMBtu

(Gas Daily) and 207,000 MMBtu (ICE). Between 2003 and 2004,

average trading volumes reported by Gas Daily increased 14%

whereas ICE trading declined 28%. The highest reported singleday Chicago citygate trading volume occurred on March 3 (Gas

Daily) and December 21 (ICE). Gas Daily and ICE trading differed

by nearly a 0.5 Bcfd at Dawn. According to Gas Daily, trading was

robust and averaged 538,000 MMBtu whereas ICE trading averaged only 63,000 MMBtu.

HUB POINTS: VOLUMES

Chicago Citygates Reported Volumes Dawn Ontario Reported Volumes

Source: Derived from Platts and ICE data. See source note 4. Source: Derived from Platts and ICE data. See source note 4.
160 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Midwest Natural Gas Market Profile Midwest Natural Gas Market Profile

NATURAL GAS INFRASTRUCTURE DEVELOPMENTS

Company Project Name Capacity Capital Cost Status Year From-To 

(MMcfd) (Millions)+ Certificated State

In-Service 

1-ANR Pipeline Company West Leg Expansion Project 220 $42 01/04 & 10/04 2003 WI-WI

2-ANR Pipeline Company East Leg Expansion Project 143 $19 Approved 2004 WI-WI

3-ANR Pipeline Company North Leg Project 107 $14 Approved 2004 WI-WI

Total 470 $75

Source: FERC Office of Energy Projects. + Capital cost figures are estimates.

Storage

LNG

Pipeline

In-Service

Filed

Approved

Directional Flow

1

2

3

1. West Leg Expansion Project

2. East Leg Project

3. North Leg Project

PROJECT DEVELOPMENT

Pipeline Projects

Only 220 MMcfd of new interstate gas pipeline capacity started

commercial service in 2004. The ANR Storage Co.’s West Leg

project serving Wisconsin entered commercial service in phases between January and October. The Midwest continued to

benefit from the nearly 7.3 Bcfd of gas pipeline capacity added

between 1999 and 2003, including 2.9 Bcfd of long-haul

pipeline from Rocky Mountain and western Canadian production areas to markets in the Midwest.8 Kinder Morgan

Interstate Transmission added 3 Bcf of working gas capacity and

169 MMcfd of deliverability to its Huntsman Storage facility in

Cheyenne County, Neb., in 2004. New facilities included 4 new

compressor units, 10 new injection/withdrawal wells, 2 new

storage field pipelines, construction of a new compressor station, and certain auxiliary or appurtenant facilities.

FERC approved construction of another 250 MMcfd of ANR

capacity in Wisconsin. Northern Border Pipeline announced

commitments from shippers to support a proposed expansion

in the Chicago market area. The $20 million Chicago

Expansion III project (130 MMcfd) requires new compressor

station construction and modifications to existing compressor

stations. The projected in-service date is April 2006; Northern

Border Pipeline filed a certificate application with FERC in

January 2005.

This map numbering system corresponds to the 

chart below on Pipeline Projects.
State of the Markets Report • June 2005 161

Midwest Natural Gas Market Profile

The Dawn Hub is an increasingly important link that

integrates gas produced from multiple basins for delivery

to customers in the Midwest and Northeast. Union Gas

Ltd, an affiliate of Duke Energy Corp, operates the hub.9

Trading activity at Dawn increased 0.7 Bcfd, or 11%, in

2004 over 2003, to 6.8 Bcfd. The principal participants

trading at Dawn include U.S. Northeast and Ontario local

distribution companies, retail energy marketers, traditional marketers, and financial institutions. Estimated

peak-day throughput was 2.6 Bcfd at Dawn, which

includes 20 depleted reservoirs with 150 Bcf of storage

capacity.10

Dawn has many of the attributes that customers seek as

they structure gas transactions at the Chicago Hub: access

to diverse sources of gas production; interconnection to

multiple pipelines; proximity to market area storage;

choice of seasonal and daily park and loan storage services;11 liquid trade markets and transparent pricing; and

opportunities to reduce long-haul pipeline capacity ownership by purchasing gas at downstream liquid hubs. 

Interest in gas service at Dawn is growing. Union Gas

concluded a binding open season for incremental transportation service between Dawn and Parkway in

December 2004. As a result, Union Gas executed firm

contracts for 370 MMcfd of capacity with average terms of

12 years. A consortium of U.S. customers was among the

23 parties that acquired this capacity. The consortium

decided to acquire a portion of its gas requirements at

Dawn rather than buy gas upstream in Alberta. Union

Gas submitted an application for the expansion project to

the Ontario Energy Board on March 22, 2005. Vector

Pipeline LP, which delivers natural gas from Chicago into

the greater Dawn market through a 1-Bcfd pipeline, held

an open season in April 2005 to add up to 0.5 Bcfd of new

capacity through the construction of additional compressor stations on its system.

Dawn Links Midwestern and Northeastern Gas Markets

Midwest Natural Gas Market Profile

MI

PA

MN

IA

IL

OH

KY

WV

MD

IN

MO

NY

CANADA

WI

Dawn Hub Parkway

Dawn Hub
162 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Midwest Natural Gas Market Profile

Depleted Aquifer Salt Total Dry Proved

Gas/Oil Cavern Storage Reserves

Sites Capacity Sites Capacity Sites Capacity Sites Capacity

(Bcf) (Bcf) (Bcf) (Bcf) (Bcf)

Illinois 12 206 17 767 0 0 29 972 0

Indiana 11 32 12 81 0 0 23 114 0

Iowa 0 0 4 273 0 0 4 273 0

Kentucky 20 211 3 10 0 0 23 221 1,889

Michigan 42 1,025 0 0 2 4 44 1,028 3,428

Minnesota 0 0 1 7 0 0 1 7 0

Missouri 0 0 1 32 0 0 1 32 0

Nebraska 1 39 0 0 0 0 1 39 0

N. Dakota 0 0 0 0 0 0 0 0 448

Ohio 24 572 0 0 0 0 24 572 1,126

West Virginia 31 511 0 0 0 0 31 511 3,306

Total 141 2,596 38 1,170 2 4 181 3,770 10,197

REGIONAL GAS SUPPLY

An extensive network of interstate pipelines gives the Midwest

region access to gas supply from western Canada and virtually

every producing basin in the United States and offshore Gulf of

Mexico. Northern Border and Alliance delivered an estimated

1.4 Tcf (3.8 Bcfd) of western Canadian gas into the Midwest.12

The region is well supplied, and customers purchase their supplies not only at the regional Chicago and Dawn hubs but also

farther upstream at the many production basins. Michigan and

West Virginia (375 Bcf) account for almost two-thirds of production within the region. Regional dry proved reserves total

10,200 Bcf.

Approximately 3.7 Tcf (46%) of U.S. gas storage capacity is

located in the Midwest market. Customers in the region rely

upon market area storage to meet winter peak requirements

and to provide no-notice service in support of peaking gas-fired

generation. The Midwest has 181 storage sites consisting of

depleted field, aquifer, and salt cavern storage capacity.

NiSource Inc., ANR,13 and NGPL own extensive storage facilities in Indiana, Iowa, Illinois, and Michigan. These storage

facilities are connected to intrastate pipeline systems and interstate pipeline systems. Columbia Gas Transmission and

Dominion Transmission Interstate own significant storage

facilities in West Virginia and Ohio connected to their web-like

systems.

This network facilitates gas movement from storage within and

out of the Midwest region. The Michigan and Chicago markets

rely upon ANR and its storage facilities. Meanwhile, states in

the Northeast and Mid-Atlantic draw heavily upon storage

capacity in West Virginia and Ohio to meet peak-day consumption during the winter.

Midwest regional working gas inventories closely mirrored 5-

year averages for the first half of 2004. A relatively mild winter

in 2003–04 (heating degree days were about 94% of normal) and

a cool summer (cooling degree days averaged 83% of normal14)

resulted in an exceptionally high working gas inventory, almost

1,400 Bcf, going into the winter withdrawal season.

Storage and Gas Reserves Overview

Regional Storage Inventory Levels

Source: Derived from EIA data. See source note 5.

0

200

400

600

800

1000

1200

1400

1600

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Working Gas Storage Inventory (Bcf)

5-year range

2004

Source: Derived from EIA data. See source note 6. Note: Totals may not equal sum of components due to rounding.
State of the Markets Report • June 2005 163

Midwest Natural Gas Market Profile

PIPELINE UTILIZATION

Midwestern Natural Gas No. Border Percent

Rank Customer Alliance ANR Gas Pipeline Pipeline Pipeline Co. Total of Total

1 Northern Illinois Gas Co. 220 327 1,350 1,897 26%

2 Peoples Gas, Light & Coke Co. 344 96 488 220 1,147 16%

3 Northern Indiana Public Service Co. 70 540 609 8%

4 North Shore Gas Co. 126 123 41 290 4%

5 Wisconsin Gas Co. 228 228 3%

6 BP Canada Energy Co. 125 80 205 3%

7 Wisconsin Electric Power Co. 122 57 179 2%

8 El Paso Merchant Energy, LP 160 160 2%

9 Burlington Resources Canada Energy Ltd 82 25 31 138 2%

10 EnCana Marketing (USA), Inc. 69 26 26 121 2%

All Others 1,140 174 53 558 278 2,203 31%

Greater Chicago Capacity by Holding Company (MMcf)

Average Annual Gas Flows (MMcfd)

-

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Transcanada Emerson

Northern Border

Alliance Pipeline

Columbia Gulf

Panhandle

Texas Eastern M1

Tennessee

NGPL West

Texas Gas

Trunkline

Vector Pipeline

Trailblazer

ANR

Northern Natural Iowa

Average Unscheduled

Flow

Average Scheduled

Flow

Source: Derived from Lippman Consulting Inc., Platts and pipeline company data.

See source note 8.

A wide variety of pipelines serve the Midwest, the largest of

which are TransCanada and Northern Border. In general,

pipelines from the Gulf Coast (for example, Panhandle, Texas

Eastern, and Tennessee) have lower utilization rates than

pipelines from the West. Customers use almost all the capacity available on some of the pipelines from farther west (for

example, Trailblazer, Northern Border, and the western leg of

Natural Gas Pipeline of America). This usage is consistent

with a pattern of lower gas prices in western producing

regions.

MARKET CONCENTRATION

Source: Derived from Platts data. See source note 7. One million Btu assumed to equal 1 Mcf.

Ownership of interstate natural gas transportation rights in the

greater Chicago market is not concentrated. Three LDCs—

Northern Illinois Gas, Peoples Gas, Light & Coke, Co., and

Northern Indiana Public Service Co.—owned about 50% of the

firm interstate natural gas pipeline delivery rights in the greater

Chicago market in 2004. The top ten shippers in this market

owned 69% of aggregate delivery rights. However, excess

pipeline capacity rights exist and market-based transportation

services reflect steep discounts, especially on U.S. Gulf Coast

pipelines. 
164 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Midwest Natural Gas Market Profile

1. Prices reflect the mid-point of day-ahead, spot transactions. All

prices reported for flow date. 

2. Prices reflect the basis or difference between the delivered price

at a downstream market hub and the price of natural gas reported at the Henry Hub for spot, day-ahead transactions.

Differences between downstream hub prices reported by Gas

Daily and the Henry Hub for every calendar flow date in a month

are averaged. 

3. Reflects near-month natural gas swap price. 

4. Trading volumes reported by Gas Daily at various market hubs

often exceed ICE reported volumes because Gas Daily may count

the same transaction twice—once from a seller’s standpoint and

once from a buyer’s standpoint. Conversely, as exchange traded

products, transactions involving two counterparties are reported

only once by ICE. 

5. Data for 2003 derived from EIA files entitled

“ng_stor_sum_dcu****.xls,” where the wild card represents the

state designation. Storage activity for 2004 derived from a file

provided by EIA, “Working Gas by State and Month – EIA

2004.xls.”

6. Storage: “Natural Gas Annual 2003,” Movements and Storage –

Table 14, EIA. Proved reserves: file

“ng_enr_dry_a_EPG0_R11_Bcf_a.xls”, Dry Natural Gas Proved

Reserves as of December 31, 2003, EIA. File as of April 1, 2005.

7. Uses the first quarter 2005 index of customers. Excludes firm

natural gas storage contracts and transportation deliveries to

other pipeline companies. Incorporates firm delivery contracts

for counties representing the greater Chicago gas market: Cook,

DuPage, Grundy, Kane, Kankakee, Kendall, Lake, McHenry, and

Will counties. 

8. Operationally available capacity data bases from Platts GasDat;

operationally available capacity information from pipeline company informational postings; “Monthly Pipeline Reports” and

“Monthly Regional Capacity Reports” from Lippman Consulting,

Inc; and OMOI analysis. 

Disclaimer: This report contains analyses, presentations, and 

conclusions that may be based on or derived from the data sources

cited, but do not necessarily reflect the positions or recommendations

of the data providers. 

1 OMOI defines the gas market in the Midwest to include 13 states in 3 subregions: West Central (Iowa, Minnesota, Missouri, North Dakota, and

South Dakota), the Upper Midwest (Illinois, Indiana, Michigan, and

Wisconsin) and the Ohio Valley (Kentucky, Ohio, and West Virginia).

2 Total imports averaged 6.2 Bcfd but approximately 2.3 Bcfd of Canadian

gas was re-exported to Canada. Some of this gas ultimately flows into the

northeast U.S. gas market.

3 Bentek Energy LLC Pipe2Pipe tool natural gas transportation analysis

tool.

4 The AECO-C/Nova Inventory Transfer market center links Canadian natural gas supplies through interconnections with a long-distance gas transportation network to markets in Canada and the U.S. Also, it is the main

pricing point for Alberta natural gas and represents the major reference

pricing point for Canadian gas. AECO-C prices are determined via the spot

market.

5 Natural gas trading hub located in Ontario, Canada; Dawn is an integral

part of the Union Gas system.

6 According to Nymex ClearPort, MichCon is a natural gas price reporting

point that encompasses Michigan Consolidated Gas Co.’s 14,700 squaremile service area and 1.2 million customers. MichCon is an operating subsidiary of DTE Energy Company.

7 Excludes swap trades executed by voice brokers and other over-thecounter exchanges. OMOI believes trading volume by voice brokers

accounts for a sizable share of swap transactions.

8 Represents capacity expansions on Northern Border in 1999 (0.69 Bcfd),

Alliance Pipeline in 2000 (1.6 Bcfd), Trailblazer in 2002 (0.32 Bcfd), and

TransCanada (0.23 Bcfd).

9 Duke Energy Corp, “Union Gas Signs Customer Contracts to Support

Natural Gas Infrastructure Expansion in Ontario,” news release, March 22,

2005. 

10 Energy Information Administration (EIA), “Natural Gas Market Centers

and Hubs,” October 2003. 

11 According to EIA, parking refers to a short-term transaction in which the

market center holds the shipper’s gas for redelivery at a later date. Often

storage facilities are used and sometimes displacement or variations in

linepack. Loaning refers to a short-term advance of gas to a shipper by a

market center that is repaid in kind by the shipper a short time later.

Loaning also is referred to as advancing, drafting, reverse parking, and

imbalance resolution.

12 Derived from information provided by Bentek Energy LLC.

13 Interests in 120 Bcf of storage capacity and peak-day withdrawal capability of 1.5 Bcfd. Partial ownership in more than 60 Bcf of storage capacity in

Michigan.

14 Derived from National Oceanic and Atmospheric Administration data.

OMOI analysis. 

Endnotes

Source notes
The Northeast1 is vulnerable to natural gas price

spikes. This condition is especially true in winter,

when space-heat gas requirements (energy used to heat

homes and businesses rather than to power industrial

processes) may coincide with the need to run gas-fired

power plants. Customers rely on an extensive network of

interstate pipelines to obtain gas from various North

American basins (e.g., Sable Island, the Western

Canadian Sedimentary Basin, Appalachia, the Gulf Coast)

because the Northeast has few native gas reserves.

Liquefied natural gas (LNG), an increasingly important

source of regional supply, accounts for up to 30% of peakday supply in New England. About 949 Bcf of underground market-area storage, located in Pennsylvania and

New York, augments long-haul pipeline deliveries during

peak periods. Estimated gas consumption declined 110

Bcf (3%) in 2004 compared with 2003. Mild weather lowered space-heat gas consumption for the residential and

commercial sectors by 7%, whereas gas-fired power needs

increased 51 Bcf (6%). The Northern Mid-Atlantic subregion accounted for 47% of total regional consumption.

Regional dependency on internationally supplied gas

increased 19%, from 985 Bcf to 1,176 Bcf, between 2003

and 2004. Estimated dry gas production in the Northeast

was unchanged. Estimated daily firm gas deliveries on

interstate pipelines to the Northeast from the Midwest

and Southeast averaged 3.7 Bcfd and 1.9 Bcfd, respectively.2

Northeast Natural Gas Market Profile

State of the Markets Report • June 2005 165

New England

New York

North Mid-Atlantic

Gas Trading Points

Gas Supply Area

LNG Terminal

$6.81

VT

ME

NH

NY

$6.86

$6.20

$6.14

$6.65

$6.57

$6.71

$6.78

$6.63

$6.54

MA

PA

NJ

MD

Tennessee Niagara

Transco Zone 6 NY

Cove Point LNG

Columbia Gas

Appalachia Texas Eastern

M-3

Iroquois

Zone 2

Iroquois 

Alonquin 

Citygates

Dracut 

Mass.

Transco Zone 6 

Non-NY

Tennessee 

Zone 6

Everett LNG

• The New England cold snap 

of January 2004 resulted in

record gas prices (more than

$70/MMBtu) and peak-day

send-out records. Market performance during January 14–16

highlighted issues related to

the adequacy of existing gasrelated infrastructure, the

challenges of gas and power

coordination, the influence of

environmental policies on fuel

use, and fuel procurement

strategies.

• Eastern Canadian gas exports

to the Northeast continued to

decline in 2004. The Canadian

National Energy Board (NEB)

estimates that Canadian East

Coast offshore production

declined from 435 MMcfd in

2003 to 405 MMcfd in 2004

due to unexpectedly high

decline rates.3 Sable gas production may turn out to be onehalf of the original estimated

reserves of 3.7 Tcf.4 Exploratory

seabed drilling off Nova Scotia

was unsuccessful in 2004;

wells were abandoned because

of the lack of hydrocarbons.5

• Average gas-trading

volumes reported by 

Platts Gas Daily and the

IntercontinentalExchange (ICE)

in the Northeast increased

markedly in 2004. For 

example, average annual 

volumes traded at Transco

Zone 6 N.Y. rose 78% (Gas

Daily) and 47% (ICE). 

Hub Prices ($ per MMBtu)

2003 2004 5-Year

Algonquin Citygates $6.51 $6.86 $5.34

Columbia Gas Appalachia $5.69 $6.14 $4.80

Dracut Mass. $6.29 $6.65 $5.13

Iroquois $6.14 $6.57 $4.98

Tennessee Zone 6 $6.45 $6.78 $5.23

Texas Eastern M3 $6.37 $6.63 $5.20

Transco Zone 6 Non-NY $6.36 $6.54 $5.23

Transco Zone 6 NY $6.45 $6.81 $5.43

Source: Derived from Platts Gas Daily data.

Source: Derived from Platts data.

2004 Average Daily Hub Prices ($ per MMBtu)

Focal Points for 2004
166 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Daily natural gas spot prices reached record levels during the

Northeast cold snap in mid-January. On January 15, gas prices for

day-ahead spot gas (Gas Daily) climbed to more than $70/MMBtu

in New England and New York City. In sharp contrast, the lowest Northeast prices reported during 2004 were about

$4.40/MMBtu. Delivered regional prices were about

$0.30–$0.40/MMBtu higher in 2004 overall, compared with 2003.

Occasionally high basis values reflected pipelines operating at

peak conditions with high space-heat demand and coincident gasdriven power load. Transco Zone 6 N.Y. basis averaged

$0.96/MMBtu for the year. 

Northeast Natural Gas Market Profile

SPOT MARKETS: PRICES AND VOLUMES

Day-ahead Spot Prices

0

5

10

15

20

Jan

FebMar

Apr

May

Jun

Jul

AugSep

Oct

Nov

Dec

Price ($/MMBtu)

ALGONQUIN CITYGATES

TRANSCO Z6 (NY)

TRANSCO Z6 (NON-NY)

COLUMBIA, APP

 Jan 15th: Algonquin citygates= $63.42

Transco Z6 NY= $45.27 

Transco Z6 (Non-NY) = $29.84

Monthly Average Basis Value to Henry Hub

0.00

2.00

4.00

6.00

Jan

Feb

Mar

Apr

May

Jun

Jul

AugSep

Oct

NovDec

Price Difference ($/MMBtu)

ALGONQUIN CITYGATES

TRANSCO Z6 (NY)

TRANSCO Z6 (NON-NY)

COLUMBIA, APP

Source: Derived from Platts data. See source note 1. Source: Derived from Platts data. See source note 2.

Source: Derived from Bentek Energy, LLC data.

Negative net imports are net exports.

Supply Disposition 2004 2003

(Bcf) (Bcf)

Total Dry Production 159 159

Production by Region

Appalachian 159 159

Other Sources of Supply (2004 Bcf)

International Supply

Imports Exports Net Imports

Canada 893 0 893

Mexico 0 0 0

LNG 283 0 283

Total 1,176 0 1,176

Interregional Pipeline Flows

Imports Exports Net Imports

to Midwest 1,366 0 1,366

to Southeast 687 0 687

Total 2,053 0 2,053

Demand Disposition 2004 2003

(Bcf) (Bcf)

Residential 1,185 1,242

Commercial 779 880

Industrial 518 519

Power 849 798

Losses and other 165 166

Total 3,495 3,605

Key End Use Markets

New England 828 824

- RI,ME,NH,MA,VT,CT

New York—NY 1,026 1,146

Northern Mid-Atlantic 1,641 1,636

- DC,DE,NJ,PA,MD

Northeast Supply Demand Statistics
The value of Transco Zone 6 N.Y. basis-swap contracts for settlement in the winter of 2004–2005 increased between March 2004

and October 2004 despite improving market fundamentals (nearrecord gas storage inventory levels and mild weather). During

this period, Transco Zone 6 swap prices for the 2004–2005 winter

strip6 increased from $1.42/MMBtu to $1.72/MMBtu (21%). The

increase was probably due to market participant concerns about

winter gas deliverability in light of hurricane-related cumulative

gas production shut-ins and markedly higher crude oil futures

prices. Transco Zone 6 basis-swap volumes reported by the New

York Mercantile Exchange’s (Nymex) ClearPort in 2004 were

about 2.5 times greater than the combined volumes for ICE physical and financial basis-swap products at Transco Zone 6 N.Y.7

State of the Markets Report • June 2005 167

FINANCIAL MARKETS: PRICES AND VOLUMES

Northeast Natural Gas Market Profile

Transco Zone 6 NY Swaps Prices from Trade Date Transco Zone 6 NY Forward and Swaps Volume

0.0

0.4

0.8

1.2

1.6

Jan

FebMar

Apr

May

Jun

Jul

AugSep

Oct

NovDec

Near-Month Swap Prices ($/MMBtu)

15-Dec-03

15-Mar-04

15-Jun-04

15-Sep-04

15-Oct-04

-

10,000

20,000

30,000

40,000

50,000

Jan

Feb

Mar

Apr

May

Jun

Jul

AugSep

Oct

Nov

Dec

Volume (1000's MMBtu)

ICE Physical

ICE Financial

Nymex ClearPort Financial

Source: Derived from Bloomberg L.P. and Nymex data. See source note 3. Source: Derived from Bloomberg L.P., ICE and Nymex data.

Average daily trading volumes reported by Gas Daily were also

greater than volumes reported by ICE at the Transco 6 N.Y. and

Algonquin citygates. Trading reported by both Gas Daily and ICE

at these points increased in 2004 compared with 2003. Average

annual volumes reported by Gas Daily increased 78% (from

179,000 MMBtu to 319,000 MMBtu) at Transco Zone 6 N.Y. and

50% (from 83,000 MMBtu to 124,000 MMBtu) at Algonquin citygates. Similarly, average annual volumes reported by ICE

increased about 47% at Transco Zone 6 N.Y. (from 79,000 MMBtu

to 117,000 MMBtu) and 40% (from 36,000 MMBtu to 51,000

MMBtu) at Algonquin citygates. 

HUB POINTS: VOLUMES

Transco Zone 6-NY Reported Volumes

0

250

500

750

1,000

Jan

FebMar

Apr

May

Jun

Jul

AugSep

Oct

NovDec

 Volume (000's MMBtu/d)

Gas Daily

ICE

Alonquin Citygates Reported Volumes

0

100

200

300

400

500

Jan

FebMar

Apr

May

Jun

Jul

AugSep

Oct

Nov

Dec

Volume (000's MMBtu/d)

Gas Daily

ICE

Source: Derived from Platts and ICE data. See source note 4. Source: Derived from Platts and ICE data. See source note 4.
168 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Northeast Natural Gas Market Profile

NATURAL GAS INFRASTRUCTURE DEVELOPMENTS

Company Project Name Capacity Capital Cost Status Year From-To 

(MMcfd) (Millions)+ Certificated State

1. Iroquois Gas Eastchester Extension 230 $174 In-Service 02/04 2001 NY-NY

2. Algonquin Gas Everett Alternative 60 $12 In-Service 10/04 2004 CT-MA-RI

3. Texas Eastern Mid-Atlantic Expansion 223 $83 In-Service 11/04 2003 PA-PA

4. Algonquin Gas I-8 System Uprate 140 $2 In-Service 12/04 2004 MA-MA

5. Tennessee Gas Tewksbury Andover Lateral 25 $8 Filed 2004 TBD MA-MA

6. Transcontinental Gas Central New Jersey Expansion 105 $13 Filed 2004 TBD NJ-NJ

Total 783 $292

Storage

LNG

Pipeline

In-Service

Filed

Approved

Directional Flow

12

7

8

3

10

11

6

5

2 4

9

1

1. Eastchester Extension

2. Everett Alternative Project

3. Mid-Atlantic Expansion Project

4. I-8 System Uprate Project

5. Tewksbury-Andover Lateral Project

6. Central New Jersey Expansion Project

7. Little Acre Interconnect

8. Mid-Atlantic Expansion Project

9. Cove Point Storage (5th tank)

10. Providence Facility Upgrade Project

11. Crown Landing LNG

12. Cove Point Expansion

PROJECT DEVELOPMENT

Pipeline Projects

Northeast gas infrastructure additions in 2004 were limited.

Iroquois Gas Transmission System, Texas Eastern

Transmission, and Algonquin Gas Transmission added 663

MMcfd of new interstate pipeline capacity in 2004. These

mainly short-haul projects fostered greater supply flexibility,

improved reliability along existing transportation routes, and

brought more gas into the constrained New York market. The

Eastchester Project was the most important. Improvements

there have enabled Consolidated Edison Inc. (ConEd), to backhaul up to 160,000 MMBtu/d of gas into its distribution system,

enhanced linkages between the New England and New York

gas markets, and helped ConEd avoid some capital outlays.8

Also, FERC approved another 130 MMcfd of pipeline capacity

and 263 MMcfd in gas storage deliverability in the Northeast.

Dominion Cove Point LNG expanded storage capacity by 2.8

Bcfd (56%) and thus increased regional flexibility. Developers

submitted applications to FERC and the U.S. Coast Guard to

build 3 Bcfd of incremental Northeast LNG send-out capacity.

This map numbering system corresponds to the following

3 charts on pipelines, storage, and LNG projects.

Source: FERC Office of Energy Projects . + Capital cost figures are estimates.
State of the Markets Report • June 2005 169

Northeast Natural Gas Market Profile

Company Project Name Capacity Deliverability Capital Cost Status Year State

(Bcf) (MMcfd) (Millions)+ Certificated

7. National Fuel Little Acre Interconnect 0 40 $1 Approved 2004 PA

8. Dominion Mid-Atlantic Expansion 5.6 223 $78 Approved 2004 PA, VA, WV

Total 5.6 263 $79

Company Project Name Capacity Send-Out Capital Cost Status Year State 

(Bcf) (Bcfd) (Millions)+ Certificated

9. Dominion Cove Point Cove Point 5th tank 2.8 1.0 $104 In Service 12/04 2004 MD

10. KeySpan Providence Upgrade No Change 0.5 $75 Filed 2004 TBD RI 

11. Crown Landing LLC Crown Landing 9.4 1.2 $500 Filed 2004 TBD NJ

12. Dominion Cove Point Cove Point Expansion 7.8 0.8 $160 Filed 2004 TBD MD

Total 20 3.5 $839

LNG Projects

Storage Projects

Source: FERC Office of Energy Projects. + Capital cost figures are estimates.

New York City Pipelines

-

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Jan

FebMar

Apr

May

Jun

Jul

AugSep

Oct

Nov

Dec

Estimated Monthly Deliveries (MMcfd)

Tennessee Gas

Texas Eastern 

Transcontinental

-

500

1,000

1,500

2,000

2,500

3,000

3,500

Jan

FebMar

Apr

May

Jun

Jul

AugSep

Oct

NovDec

Estimated Monthly Deliveries (MMcf)

Algonquin

Everett LNG

Maritimes & Northeast

Portland NG and

Iroquois Gas Transmission

Tennessee Gas Pipeline

Source: Derived from Platts data. See source note 5. Source: Derived from Platts data. See source note 6.

MARKET SHARES

New England Pipelines

Source: FERC Office of Energy Projects. + Capital cost figures are estimates.

Average monthly gas deliveries into both the greater New York

City market and New England peaked at about 3,500 MMcfd in

January 2004. Transcontinental Gas Pipeline and Texas Eastern

Gas Transmission delivered more than 80% of New York City’s

gas in 2004. Pipeline market shares in the broader New England 

market were divided among a variety of players.
170 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Northeast Natural Gas Market Profile

MARKET CONCENTRATION

Iroquois Gas Tennessee Gas Texas Eastern Transcontinental Total Est Share

Holding Company Firm Cap 

1 Public Service Enterprise Group, Inc 94 633 928 1,654 31%

2 KeySpan Corp 168 74 348 533 1,123 21%

3 New Jersey Resources Corp 40 14 950 24 1,028 20%

4 Consolidated Edison Inc 100 140 128 417 785 15%

All others 233 201 207 39 680 13%

Customer Algonquin Gas Iroquois Gas Maritimes & NE Portland Natural Tennessee Total Est Share 

1 Keyspan Corp 479 86 1 722 1,288 17%

2 Energy East Corp. 173 88 432 693 10%

3 Northeast Utilities 231 105 203 539 8%

4 NSTAR 256 185 441 7%

5 NiSource Inc 106 80 204 390 6%

6 International Power PLC 140 35 72 247 5%

7 Groupe Suez Lyonnaise des Eaux 121 108 229 5%

8 Dominion Resources, Inc 215 215 5%

9 PG&E Corp 186 25 211 4%

10 Duke Energy Corp 94 105 199 4%

All others 439 30 492 132 708 1,802 29%

New England Capacity by Holding Company (MMcf)

Greater NYC Capacity by Holding Company (MMcf)

Most New York City area capacity rights were held by gas and

electric distribution utilities. Four companies—Public Service

Enterprise Group, KeySpan, New Jersey Resources, and

Consolidated Edison—owned nearly 87% of the aggregate firm

interstate pipeline capacity rights associated with the greater

New York City gas market at the end of 2004. New York City

capacity rights were distributed among several pipelines.

Ownership of firm interstate pipeline capacity rights was far

less concentrated in New England. The top 5 firm pipeline

capacity rights owners controlled about 48% of the delivery

rights into New England at the end of 2004. KeySpan was the

principal company that owned significant shares of firm transportation service rights in both markets (21% in New York

City and 17% in New England). Independent power generators and energy marketers accounted for almost a quarter of

firm transportation rights in New England.

Source: Derived from Platts data. See source note 8. One million Btu assumed to equal 1 Mcf.

Source: Derived from Platts data. See source note 7. One million Btu assumed to equal 1 Mcf.
State of the Markets Report • June 2005 171

REGIONAL GAS SUPPLY

Northeast Natural Gas Market Profile

A modest amount of regional production comes from

Pennsylvania and New York and is supplemented with supplies

from the Appalachian Basin states of West Virginia, Ohio, and

Kentucky. Significant additional amounts of gas come from

Sable Island off Nova Scotia, the Western Canadian

Sedimentary Basin, and the Gulf Coast, and enter the region by

way of an extensive interstate pipeline network. The Northeast

imported 893 Bcf of natural gas from Canada in 2004 through

the following pipelines: Iroquois Gas Transmission (320 Bcf, or

36%), Tennessee Gas Pipeline (288 Bcf, or 32%), the Maritimes

& Northeast Pipeline (131 Bcf, or 15%), TransCanada Gas

Pipeline (106 Bcf or 12%), and Portland Natural Gas

Transmission System (47 Bcf, or 5%).9 Regional dry gas proved

reserves total about 2,900 Bcf.

The Northeast is highly dependent on stored natural gas, especially during the winter. Customers rely on a mix of regional

market area storage assets as well as upstream storage facilities

located in Gulf Coast states, the Midwest, and Canada.

Conventional storage capacity in the Northeast is located in

New York (201 Bcf) and Pennsylvania (748 Bcf). Satellite LNG

storage facilities, used to augment retail delivery, are located

throughout the Northeast and complement gas delivery from

more conventional storage. For example, New England has

about 14.9 Bcf of LNG storage capacity; the Distrigas LNG

import terminal has another 3.4 Bcf of storage capacity. 

Working gas storage inventories in the Northeast totaled

180 Bcf at the start of the 2004 injection season in April, an

amount 11 Bcf higher than the most recent 5-year average of

169 Bcf. Working gas storage inventories had been that high in

only 2 of the previous 5 years. A combination of economic

incentives to inject gas into storage and cool summer weather

resulted in robust gas storage injections from April through

October.10 By the onset of the withdrawal season in November,

Northeastern storage inventories totaled 497 Bcf, or about 34

Bcf above the 5-year average (463 Bcf).

Depleted Aquifier Salt Total Dry Proved 

Gas/Oil Cavern Storage Reserves

Sites Capacity Sites Capacity Sites Capacity Sites Capacity

(Bcf) (Bcf) (Bcf) (Bcf) (Bcf)

New York 22 198 0 0 1 2 23 201 365

Pennsylvania 50 748 0 0 0 0 50 748 2,487

Total 72 946 0 0 1 2 73 949 2,852

0

100

200

300

400

500

600

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sept

Oct

Nov

Dec

Working Gas Storage Inventory (Bcf)

5-year range

2004

Regional Storage Inventory Levels

Source: Derived from EIA data.See source note 10.

Source: Derived from EIA data. See source note 9.

Storage and Gas Regional Overview
172 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Northeast Natural Gas Market Profile

Stakeholders continue to examine the adequacy of

Northeast natural gas infrastructure because of consecutive

winter natural gas price spikes during 2003, 2004, and

2005.11 A complex set of factors affects decision-making by

market participants about firm transportation service

requirements: risk preferences; supply reliability needs;

near-term and long-term expectations about cumulative

pipeline basis values; utilization of existing pipeline capacity; cost of incremental gas infrastructure; and fuel-related,

cost pass-through provisions contained in power sales

agreements; or local distribution company (LDC) purchased-gas adjustments. Periodic gas and power price

spikes during coincidental winter peaks will continue in

the Northeast, particularly New England, until additional

pipeline capacity and LNG vaporization capacity is added. 

Developing new natural gas pipeline capacity in the

Northeast remained challenging in 2004 because: 

• Developers will not build new pipeline capacity without

long-term, firm transportation contracts. It is unclear,

however, who will sign up for firm transportation service. Space-heat LDC gas consumption is growing moderately and thus will limit the need for incremental firm

service. For several reasons, gas-fired power generators

continue to limit their exposure to firm transportation

reservation charges by not contracting. Monthly capacity factors for combined-cycle gas plants in 2004 in areas

managed by independent system operators (ISOs) in

New England and New York averaged between 33% and

50%. ISO-NE capacity payments are insufficient to cover

the cost of firm transportation service, and interruptible

transportation service remains reliable in the summer

and shoulder periods. 

• Buying incremental firm transportation service is uneconomical for many market participants. Despite historically high average annual basis at key trading points in

the Northeast during 2003 and 2004, the frequency and

duration of spikes have not yet justified buying firm

transportation on straight economic grounds. Given

load factor assumptions, receipt point locations, and the

extent of weather-driven price volatility, however, the

Northeast gas market is nearing a tipping point: Net-forward transactions involving upstream gas supply purchase, coupled with firm transportation service on some

pipelines, may be competitive with buying spot gas at

some downstream market hubs. 

• New pipeline capacity will cost more than existing capacity. Opportunities to increase gas deliverability into the

Northeast through relatively low-cost compression

expansions are limited12; therefore it is likely that new

gas-pipeline capacity will require at least some looping13

and will result in higher cost-based rates. Increases in

current pipeline tariffs might exceed 20%.14 Further, current tariff rates are based on assets that are significantly

depreciated and reflect lower materials costs. 

• Local opposition may slow down infrastructure development. Even if developers can construct new facilities

economically, infrastructure projects may not get built if

developers cannot allay the safety, environmental, and

other concerns of regional stakeholders. New LNG projects, if sited, will also require new pipeline infrastructure

to get this gas to market. LNG developers unable to

secure long-term contracts from gas end-users will have

to bear the price risk. They will also have to bear the volume risk, but will do so only if they are assured of access

to the pipeline grid. 

Price Points 2000 2001 2002 2003 2004

Algonquin Citygates 0.77 0.48 0.45 1.07 1.01

Columbia (APP) 0.19 0.20 0.17 0.24 0.29

Dracut (Into Tennessee) 0.74 0.11 0.24 0.84 0.80

Iroquois 0.26 0.18 0.13 0.69 0.72

Niagara (NFG, Tenn.) 0.19 0.23 0.13 0.50 0.35

Tennessee Zone 6 0.56 0.37 0.38 1.00 0.93

Texas Eastern M3 0.16 0.41 0.37 0.92 0.78

Transco Zone 6 (Non-NY) 0.80 0.45 0.37 0.91 0.69

Transco Zone 6 (NY) 1.16 0.63 0.50 1.01 0.96

Source: Derived from Platts data. See source note 11.

Recent Basis Trends ($/MMBtu to Henry Hub)

Northeast Gas Transportation Challenges
State of the Markets Report • June 2005 173

Northeast Natural Gas Market Profile

PIPELINE UTILIZATION

Average Annual Gas Flows (MMcfd)

0

500

1000

1500

2000

2500

3000

3500

4000

Transco Zone 6

Texas Eastern M3

Iroquois Gas Transmission System

Tennessee Gas Pipeline

Dominion Cove Point LNG

Everett LNG

Maritimes & Northeast Pipeline

Columbia Gas Transmission

Portland Natural Gas Transmission System

Average Unscheduled Flow

Average Scheduled Flow

The principal pipelines delivering gas into the Northeast in

2004 were Transcontinental Gas Pipeline, Texas Eastern

Transmission, and Tennessee Gas Pipeline. Transcontinental

was the most heavily used; its average daily deliveries exceeded

2,600 MMcfd. Transcontinental’s annual system load factor

averaged about 76%. Iroquois Gas Transmission System reported the highest average annual load factor of any pipeline in the

Northeast (92%). The Maritimes & Northeast Pipeline’s load

factor, on the other hand, averaged less than 50% due to ongoing productive capacity problems at Sable Island. Overall

pipeline use in the Northeast was highly seasonal and averaged

about 60% in 2004. 

Source: Derived from Lippman Consulting Inc., Platts , and pipeline company data. See source

note 12.

1 The Northeast gas market includes three principal subregions:

New England (Connecticut, Maine, Massachusetts, New

Hampshire, Rhode Island, and Vermont), New York, and the northern Mid-Atlantic (Delaware, the District of Columbia, Maryland,

New Jersey, and Pennsylvania).

2 Derived from information provided by Bentek Energy LLC. 

3 National Energy Board, “Short-term Canadian Natural Gas

Deliverability: 2004-2006,” November 2004. 

4 Moody’s Investor Service Report, February 18, 2005. 

5 The following exploratory wells drilled in the offshore region of

Nova Scotia in 2004 were abandoned: Exxon-Mobil’s Cree I-34,

EnCana’s Weymouth A-45, Canadian Superior’s Mariner I-85, and

Marathon’s Crimson F-81. “New England Natural Gas Supply

Assessment,” April 1, 2005, Merrimack Energy Group, 11–12. 

6 The simple average of Transco Zone 6 basis prices for November

2004 through March 2005. 

7 Excludes swap trades executed by voice brokers and on other

over-the-counter exchanges. OMOI believes trading volume by

voice brokers accounts for a sizable share of swap transactions. 

8 Herbert Rakebrand and Associates LLC, “Northeast Natural Gas

Infrastructure Assessment,” April 1, 2005, 12–13.

9 Derived from data provided by Bentek Energy LLC.

10 In 2004, the estimated difference between the daily average cost

of buying gas to inject in storage ($5.83/MMBtu at the Henry Hub)

versus buying winter natural gas futures contracts ($6.85/MMBtu

at the Henry Hub) was $1.02/MMBtu. This amount is more than

twice the benchmark ($0.48/MMBtu) assumed to cover customary

carrying costs for natural gas stored in depleted field reservoirs.

This spread ranged between $0.31/MMBtu and $2.65/MMBtu.

11 “Northeast Natural Gas Infrastructure Assessment,” developed for

ISO-NE by Herbert Rakebrand and Associates, April 1, 2005; “New

York Markets Lack Key to Avoid Winter Energy Price Spikes,”

Cambridge Energy Research Associates Decision Brief, July 12,

2004; and “Final Report on Electricity Supply Conditions in New

England During the January 14–16, 2004 ‘Cold Snap’,” ISO New

England Inc. Market Monitoring Unit, October 12, 2004.

12 A notable exception entails adding compression to the Maritimes

& Northeast Pipeline to deliver potential greenfield LNG from proposed import terminals in eastern Canada. “New England Gas

Supply Assessment,” developed by Merrimack Energy Group for

ISO New England, April 1, 2005, 2.

13 Construction of new segments of pipe meant to parallel and interconnect with existing infrastructure.

14 Analysis by Shree Vikas, Science Applications International

Corporation. 

Endnotes
174 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Northeast Natural Gas Market Profile

1. Prices reflect the midpoint of day-ahead, spot transactions. All

prices reported for flow date. 

2. Prices reflect the basis or difference between the delivered price

at a downstream market hub and the price of natural gas reported at the Henry Hub for spot, day-ahead transactions.

Differences between downstream hub prices reported by Gas

Daily and the Henry Hub for every calendar flow date in a month

are averaged. 

3. Reflects near-month natural gas swap price. 

4. Trading volumes reported by Gas Daily at various market hubs

often exceed ICE reported volumes because Gas Daily may count

the same transaction twice—once from a seller’s standpoint and

once from a buyer’s standpoint. Conversely, as exchange traded

products, transactions involving two counterparties are reported

only once by ICE. 

5. Texas Eastern, Transcontinental Gas Pipeline, and Tennessee

Gas Pipeline net natural gas deliveries minus receipts to New

York City boroughs plus various New Jersey counties. Transco:

deliveries at Linden. Texas Eastern: New York deliveries to

Richmond, and New Jersey deliveries to Hunterdon, Middlesex,

Morris, Passaic, Somerset, and Union counties. Tennessee:

New York deliveries to Kings, Westchester, and Rockland counties plus New Jersey deliveries to Bergen, Passaic, and Sussex

counties. 

6. Represents natural gas imports into the New England market on

interstate natural gas pipelines plus deliveries into Algonquin

Gas Transmission and Tennessee Gas Pipeline via the Everett

LNG facility. Does not account for LNG delivered by truck to LDCs

from Everett. 

7. Accounts for firm transportation service right market shares of

FERC-jurisdictional pipelines with primary delivery point rights

to the greater New York City market. Conversely, excludes firm

interstate pipeline transportation rights held by shippers with

delivery points designated upstream of the northern New Jersey

and New York City markets according to first quarter 2005 index

of customers information reported in Platts’ GasDat. 

8. Accounts for firm transportation service rights on FERC-jurisdictional pipelines with primary delivery point rights to meters

located in New England. 

9. Gas Annual 2003,” Movements and Storage – Table 14. EIA.

Proved reserves: file “ng_enr_dry_a_EPG0_R11_Bcf_a.xls”, Dry

Natural Gas Proved Reserves as of December 31, 2003, EIA. File

as of April 1, 2005. 

10. “Natural Data for 2003 and prior derived from EIA files entitled

“ng_stor_sum_dcu****.xls,” where the wild card represents the

state designation. Storage activity for 2004 derived from a file

provided by EIA, “Working Gas by State and Month – EIA

2004.xls.” 

11. Basis values represent the average annual difference in marketbased transportation costs between various downstream price

points and the Henry Hub. 

12. Operationally available capacity data bases from Platts GasDat;

operationally available capacity information from pipeline company informational postings; “Monthly Pipeline Reports” and

“Monthly Regional Capacity Reports” from Lippman Consulting,

Inc; and OMOI analysis. 

Disclaimer: This report contains analyses, presentations, and conclusions that may be based on or derived from the data sources

cited, but do not necessarily reflect the positions or recommendations of the data providers. 

Source notes
As the key natural gas producing region in the United

States, the South Central region accounted for 12.5 Tcf

(68%) of dry gas production and nearly 99 Tcf (55%) of

proved dry natural gas reserves estimated to exist in the

Lower 48 in 2004. Key regional sources of gas production

included the federal and state offshore areas,

Midcontinent, Permian, East Texas, South Texas, and

Arkoma basins. Most of the nation’s high deliverability salt

cavern storage capacity is located in Texas and Louisiana,

and South Central had more than 2.3 Tcf of natural gas

storage capacity to augment the region’s gas gathering and

processing, production, and pipeline networks. 

Although a net exporter of natural gas, South Central consumed 27% of total, Lower 48 dry gas production in 2004

and accounted for 35% of total Lower 48 gas consumed by

the power generation sector. Total gas consumption

declined 1% or 187 Bcf. Estimated firm interstate gas

exports to other U.S. regions exceeded 6 Tcf, or 17 Bcfd.1

Despite historically high natural gas prices in 2004, industrial sector gas use still topped all sectors (51% of total

regional consumption). Many of the liquid production

area trading points used as benchmarks for pricing natural

gas commodity services are located in this region. Trade

publications regularly report prices at about 40 locations in

this market. Natural gas production in South Central is

not concentrated. No company accounted for more than

4% of regional production in 2004.2 The top 25 exploration

and production companies in the region accounted for

about 5 Tcf, or 39%, of the 12.5 Tcf of estimated total

regional dry production in 2004. 

South Central Natural Gas Market Profile

State of the Markets Report • June 2005 175

KS

AK

OK

TX

LA

Texas

South Central, Other

Gas Trading Points

Gas Supply Area

LNG Terminal

$5.64 $5.79 $5.38

$5.40

$5.85 $5.83 $5.64

$5.67

Tennesse

Zone 0

Waha NGPL, 

Texok Zone

NGPL, Midcontinent

Southern

Natural, La

Texas Eastern, ELA.

Henry Hub

Katy

Lake 

Charles

• More project investment.

Developers proposed construction of six new 

liquefied natural gas (LNG)

import terminals that could

lead to a total average sendout of 8.3 Bcfd. Meanwhile,

the U.S. Coast Guard and FERC

approved five LNG import projects representing 6.2 Bcfd of

send-out in 2004, including

the Sabine Pass Project—the

largest LNG facility certificated

to date in the United States

(2.6 Bcfd). Together, send-out

from these facilities represented 11% of average daily gas

use in the United States in

2004 (59 Bcfd). 

• Increased industrial gas consumption. Estimated use rose

1% despite high gas prices. 

• Increased trading. Reported

trading volume at Henry Hub

increased 16% compared with

2003.

• Faulty futures price. The 

near-month futures contract

for December gas at Henry

Hub increased $1.18/MMBtu

in response to an erroneously

reported 49-Bcf gas storage

withdrawal on November 24,

2004. 

• Reduced regional production.

Production declined to 12.5 Tcf

(-0.5%) despite the addition of

100 operating rigs for a total of

846.3 Texas was the only state

in the region to register a 

significant production increase

(~23 Bcf) from 2003, largely

because production from the

Barnett Shale fields increased

22% to 368 Bcf. 

• Reduced LNG volume.

Average daily Lake Charles

LNG send-out volume declined

by 30% (from 656 MMcfd in

2003 to 460 MMcfd in 2004)

because of terminal construction, reliance upon spot cargoes,

and cargo diversions. 

Hub Prices ($ per MMBtu)

2003 2004 5-Year

Henry Hub $5.44 $5.85 $4.58 

Katy $5.36 $5.67 $4.50

NGPL, Midcontinent $5.11 $5.40 $4.32

Southern Natural, La $5.38 $5.83 $4.53

Tennessee Zone O $5.26 $5.64 $4.42

Waha $5.17 $5.38 $4.35

NGPL Texok Zone $5.31 $5.64 $4.46

Source: Derived from Platts data.

Source: Derived from Platts data.

2004 Average Daily Hub Prices ($ per MMBtu)

Focal Points for 2004
176 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

The annual average spot gas price at the Henry Hub climbed from

$5.44/MMBtu to $5.85/MMBtu or about 7% between 2003 and

2004. Overall, prices throughout the South Central region rose

6% in 2004. Daily prices reported at the Henry Hub ranged

between $4.33/MMBtu and $8.12/MMBtu. All pricing points

traded at a discount to the Henry Hub on an average monthly

basis throughout the year because they are located upstream of the

Henry Hub pricing point. Production problems caused by

Hurricane Ivan led to historically high negative basis values (up to

$1/MMBtu) between the Midcontinent and west Texas markets

and gulf-sourced gas in the region. 

South Central Natural Gas Market Profile

SPOT MARKETS: PRICES AND VOLUMES

Day-ahead Spot Prices Monthly Average Basis Value to Henry Hub

Source: Derived from Platts data. See source note 1. Source: Dervied from Platts data. See source note 2.

Source: Derived from Bentek Energy, LLC data. Note: Negative net imports are net exports.

Supply Disposition 2004 2003

(Bcf) (Bcf)

Total Dry Production 12,521 12,587

Production by Region

Texas Gulf Coast 2,119 2,115

Anadarko 1,432 1,452

Permian-Texas 1,190 1,142

East Texas 1,029 935

Other 6,752 6,943

Other Sources of Supply (2004 Bcf)

International Supply

Imports Exports Net Imports

Mexico 0 153 (153)

LNG 170 0 170

Total 170 153 17

Interregional Pipeline Flows Net Imports

To Midwest (1,706)

To Southeast (4,928)

To West 591

Total (6,042)

Demand Disposition 2004 2003

(Bcf) (Bcf)

Residential 394 428

Commercial 304 351

Industrial 3,013 2,995

Power 1,844 1,958

Losses and Other 301 310

Total 5,856 6,043

Key End Use Markets

Texas 3,756 3,928

Other- AR, KS, LA, OK 2,100 2,115

Supply Demand Statistics
As usual, expectations for summer 2004 basis differentials

between the Houston Ship Channel and the Henry Hub narrowed, averaging between -$0.05/MMBtu and -$0.10/MMBtu.3

The average anticipated basis between Houston Ship Channel

and Henry Hub almost doubled, however, from 

-$0.14/MMBtu to -$0.25/MMBtu, between December 2003

and October 2004, as the market factored in higher gas prices

associated with hurricane-related production shortfalls. Traded

volumes for Houston Ship Channel financial swaps (47,000,000

MMBtu) on the New York Mercantile Exchange (Nymex)

exceeded IntercontinentalExchange (ICE) swaps (9,500,000

MMBtu) by 5-to-1.4 No physical trades were reported by ICE at

the Houston Ship Channel; ICE did report limited trading activity at the nearby Katy storage hub in August and October. 

State of the Markets Report • June 2005 177

FINANCIAL MARKETS: PRICES AND VOLUMES

South Central Natural Gas Market Profile

Houston Ship Channel Swaps Prices from Trade Date Houston Ship Channel Forward and Swaps Volume

Source: Derived from Bloomberg, L.P. and Nymex data. See source note 3. Source: Derived from ICE and Nymex data.

Average daily trading volume at Henry Hub grew measurably in

2004. According to Gas Daily, average traded volume increased

18%, from 701,000 MMBtu to 831,000 MMBtu. ICE reported a

similar percentage increase (16%), as average daily volume grew

from 604,000 MMBtu to 698,000 MMBtu. In October, Henry

Hub trading activity on Nymex’s ClearPort and on ICE doubled

that of prior months and continued at robust levels during

November and December. Significant trading took place at the

Natural Gas Pipeline Co. of America’s Texok point in 2004; average daily reported volume ranged between 277,000 MMBtu (ICE)

and 400,000 MMBtu (Gas Daily).

HUB POINTS: VOLUMES

Henry Hub Reported Volumes NGPL Texok Reported Volumes

Source: Derived from Platts and ICE data. See source note 4. Source: Derived from Platts and ICE data. See source note 4.
178 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

South Central Natural Gas Market Profile

NATURAL GAS INFRASTRUCTURE DEVELOPMENTS

Company Project Name Capacity Capital Cost Status Year From-To 

(MMcfd) (Millions)+ Certificated State

1. NGPL Black Marlin 60 $1 In-Service 11/04 2004 OK-TX

2. CenterPoint Round Mountain and Helena Stations 70 $10 Approved 2004 AR-AR

Total 130 $11

Pipeline Projects

Storage

LNG

Pipeline

In-Service

Filed

Approved

Directional Flow

1

4

3

2

9

105

8

7 11

14

6

13 12

15

1. Black Marlin Pipeline Project

2. Round Mountain and Helena Stations

3. Pine Prairie Energy Center Projects

4. Sayre Storage Expansion

5. Freeport LNG

6. Modified Expansion Project

7. Sabine Pass LNG

8. Golden Pass LNG Terminal

9. Vista Del Sol LNG Terminal

10. Ingleside Energy Center LNG Terminal

11. Port Arthur LNG

12. Port Pelican

13. Pearl Crossing

14. Gulf Landing

15. Gulf Gateway

This map numbering system corresponds to the 

following three charts on pipeline, storage, and 

LNG projects. 

PROJECT DEVELOPMENT

LNG import proposals dominated South Central regional

infrastructure activity in 2004. Five LNG import terminal

projects with a total send-out of 6.2 Bcfd were approved—

three by the Commission and two by the U.S. Coast Guard.5

Project developers filed applications to construct six more terminals, which could enhance LNG send-out within the

region by 8.3 Bcfd. The applicants cited several regional

advantages for development, including fuel-blending opportunities, liquid markets, robust existing infrastructure,

national market access, deepwater ports, acreage, and proximity to nearby salt storage caverns. Only 0.13 Bcfd of new interstate capacity was brought on line or approved. Intrastate

pipelines account for much of the pipeline capacity serving

this market. 

The Commission approved Sempra Global’s multi turn salt

cavern project—the Pine Prairie Energy Center—in

November. The project is expected to be available for service

in fourth quarter 2005. When completed, the facility will provide up to a total of 24 Bcf of storage capacity in three 8 Bcf

caverns, with up to 2.4 Bcfd of withdrawal, and up to 1.4 Bcfd

of injection capabilities, (6-to-12 turn annual service).

Source: FERC Office of Energy Projects. + Capital cost figures are estimates.
State of the Markets Report • June 2005 179

South Central Natural Gas Market Profile

Company Project Name Capacity Deliverability Capital Cost Status Year State

(Bcf) (Millions)+ Certificated

3. Pine Prairie Pine Prairie 24 2,400 $180 Approved 2004 LA

4. NGPL Sayre 10 200 $33 Filed 2004 TBD OK

Total 34 2,600 $213 

Storage Projects

Company Project Name Capacity Send-Out Capital Cost Status Year State 

(Bcf) (Bcfd) (Millions)+ Certificated

5. Freeport Freeport 7.0 1.5 $500 Approved 2005 TX

6. Trunkline Modified Expansion 2.9 1.2 $87 Approved 2004 LA

7. Cheniere Sabine Pass 10.4 2.6 $450 Approved 2004 TX

8. Golden Pass Terminal LP Golden Pass LNG Terminal 9.8 1.0 $600 Filed 2004 TBD TX

9. ExxonMobil Vista del Sol 9.8 1.0 $600 Filed 2004 TBD TX

10. Ingleside Energy Ingleside LNG Terminal 6.8 1.0 $400 Filed 2004 TBD TX

11. Sempra Port Arthur LNG 10.1 1.5 $600 Filed 2004 TBD TX

12. Chevron Port Pelican * 10.3 1.6 $700 Approved 2004 LA

13. ExxonMobil Pearl Crossing * 10.6 2.8 $231 Filed 2004 TBD Gulf of Mexico

14. Shell US Gas & Oil Gulf Landing * 4.2 1.0 $700 Filed 2004 TBD Gulf of Mexico

15. Excelerate Energy Gulf Gateway* 0.5 0.5 $200 Approved 2004 Gulf of Mexico

Total 79.5 14.5 $5,068 

LNG Projects

Source: FERC Office of Energy Projects. * Coast Guard Jurisdictional. + Capital cost figures are estimates.

The average number of rigs operating in the South Central

region grew to 846 in 2004 from 736 in 2003. Despite this

increase, preliminary estimates indicate that regional dry gas

production declined 0.5% to 12.5 Tcf in 2004. Preliminary

Texas Railroad Commission data for 2004 show a slight

increase (23 Bcf) above 2003 production, with production in

Texas accounting for 62% of South Central dry gas production.

Oklahoma and Louisiana accounted for 16% and 14%, respectively. Preliminary figures from those two states show slight

declines in 2004 production. Accelerated decline rates for

existing and newly producing wells continued to plague the

industry, as did the lack of trained personnel to operate the

rigs. Growing interest in the Barnett Shale in northeast Texas

and higher natural gas prices spurred rig activity in 2004.

Production Remains Flat Despite Growth in Rig Counts

Source: FERC Office of Energy Projects. + Capital cost figures are estimates.

Rig Count and Production

Source: Derived from Baker, Hughes and Lippman Consulting, Inc. data. See source note 5.
180 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

South Central Natural Gas Market Profile

REGIONAL GAS SUPPLY

The South Central region, combined with offshore production

in the Gulf of Mexico, accounted for almost 68% of total dry gas

production in the Lower 48 states. Although land-based production in the region rose 4% (385 Bcf), offshore production

fell 10% (520 Bcf) from 2003 to 2004. According to the

Minerals Management Service (MMS), estimated Gulf of

Mexico shallow water gas production decreased to 7.3 Bcfd, or

by 0.9 Bcfd, in 2004; deepwater gas production remained

unchanged at 3.9 Bcfd.6 Increased production from the Barnett

Shale in north Texas offset declining production in the mature

shallow water Gulf of Mexico fields. Proved dry reserves

amounted to more than 76,900 Bcf. 

According to the latest Energy Information Administration

(EIA) data, proved dry gas reserves in the Lower 48 increased

1% (2,098 Bcf) to 189,044 Bcf in 2003.7 Thus, 2003 was the fifth

year in a row (and ninth out of the last 10) in which proved gas

reserves increased. Most of the increase came from extensions

of existing conventional and unconventional gas fields. Gulf of

Mexico Federal Offshore proved dry gas reserves, which

accounted for 12% of the total, fell 11% (2,825 Bcf) to 22,570

Bcf from 2002. Thus 2003 also was the second year in a row in

which a decline in such reserves occurred. By contrast, national coalbed methane reserves, which accounted for 10% of

proved dry gas reserves, increased 1% (252 Bcf) to 18,743 Bcf. 

As of 2004, more than 2.3 Tcf of storage capacity at 81 sites was

distributed throughout the South Central region. Storage operations are well integrated with the interstate and intrastate

pipeline network, with enough flowing gas from producing

wells to efficiently manage daily fluctuations in production and

consumption. Salt cavern storage represented 39% of total

regional storage deliverability, even though it accounted for

only 8% of regional storage capacity. 

On August 19, Cavern 1 at the Moss Bluff storage facility caught

fire. Moss Bluff is located about 40 miles northeast of Houston

and consists of three salt caverns totaling 16 Bcf of working gas

capacity. Rain and cool temperatures in the days that followed

minimized the effects of the fire on the market. Before the fire

burned itself out on August 25, approximately 6 Bcf of gas was

released and burned. As a safety precaution, Caverns 2 and 3

were shut in temporarily; they returned to service in

November. Cavern 1 returned to service in April 2005.

Source: Derived from EIA data. See source note 7.

Depleted Aquifier Salt Total Dry Proved

Gas/Oil Cavern Storage Reserves

Sites Capacity Sites Capacity Sites Capacity Sites Capacity

(Bcf) (Bcf) (Bcf) (Bcf) (Bcf)

Arkansas 2 22 0 0 0 0 2 22 1,663

Kansas 17 287 0 0 1 1 18 288 4,819

Louisiana 8 530 0 0 6 61 14 592 9,325

Oklahoma 13 385 0 0 0 0 13 385 15,401

Texas 20 548 0 0 14 114 34 663 45,730

Total 60 1,772 0 0 21 176 81 1,950 76,938

Source: Derived from EIA data. See source note 6.

Regional Storage Inventory Levels

Storage and Gas Reserves Overview
State of the Markets Report • June 2005 181

South Central Natural Gas Market Profile

PRODUCTION TRENDS

South Central regional production results were mixed in 2004.

Generally flat or declining production in many traditional,

onshore, and inland conventional gas basins was offset by

increased production from unconventional gas basins such as the

Barnett Shale deposit in the Fort Worth Basin and the Bossier and

Cotton Valley tight sands deposits in the East Texas Basin. In 2004,

production from the East Texas Basin increased by almost 94 Bcf

(10%) to 1,029 Bcf from 2003. Production from the Barnett Shale

was even more successful. According to the Texas Railroad

Commission, the Barnett Shale produced 368 Bcf of natural gas in

2004, an increase of more than 170 Bcf (22%) from 2003.8

However, those production successes were not enough to offset

production declines in the shallow water area of the Gulf of

Mexico. Gulf of Mexico production is a major portion of U.S. supply and accounted for 22% of annual Lower 48 natural gas production. Shallow water production has been declining since 1996,

when production was more than 4,800 Bcf, and the Minerals

Management Service estimates that 2004 production fell by 329

Bcf (11%) to 2,665 Bcf from 2003.9 Further, deepwater production

from the Gulf of Mexico has not been as successful as expected.

Production in 2004 was unchanged from 2004; some estimates

show that deepwater production may have hit its peak, and will

generally decline through 2012, except for a slight increase in 2008

when eight new discoveries are expected to begin production.10

Expected production increases from the deepwater portion of the

Gulf of Mexico have not occurred due to, among other things, a

recent lack of nonassociated gas discoveries, slow company

approval of field development, more rapid than expected declines

in some existing fields, and the removal of some earlier discoveries from expected development until after 2010 for economic reasons.11

Thus, despite increased drilling and production successes in the

Fort Worth and East Texas basins, gas supply from the South

Central Region is struggling as production from traditional, conventional shallow water Gulf of Mexico fields continues to

decline.

Barnett Shale Production Trends

Gulf of Mexico Production

Source: Derived from MMS data. See source note 8.

Source: Derived from Lippman Consulting Inc., Quarterly Regional Production

Reports, Report #407, February 22, 2004.
182 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

South Central Natural Gas Market Profile

PIPELINE UTILIZATION

Average Annual Gas Flows (MMcfd)

Endnotes

1

Derived from information provided by Bentek Energy LLC. 

2

Based on analysis of production trends reported by Lippman

Consulting Inc. 

3

Approximately 86% of U.S. operating rigs are gas-directed.

4

Excludes swap trades executed by voice brokers and other overthe-counter exchanges. OMOI believes trading volume by voice

brokers accounts for a sizable share of swap transactions. 

5

The Commission is the lead agency responsible for the preparation of the analysis and decisions required under the National

Environmental Policy Act for the approval of new facilities. Under

the Natural Gas Act, the Commission has the lead responsibility

for authorizing the construction and siting of LNG facilities

onshore and within state waters. The U.S. Coast Guard has 

primary authority over construction and siting of offshore LNG

facilities. 

6

Minerals Management Service (MMS), “Deepwater Gulf of Mexico

2005: Interim Report of 2004 Highlights,” Outer Continental Shelf

(OCS) Report, MMS 2005-023, May 2005. 

7

Energy Information Administration, U.S. Crude Oil, Natural Gas,

and Natural Gas Liquids Reserves, 2003 Annual Report,

September 2004.

8

As reported by the Fort Worth Star-Telegram, February 22, 2005.

9

Minerals Management Service, “Deepwater Gulf of Mexico 2005:

Interim Report of 2004 Highlights,” OCS Report, MMS 2005-023,

May 2005, Appendix C.

10 Cambridge Energy Research Associates, “North American Gas

Capacity Race, Can Unconventional Gas Offset the Increased

Decline in the Gulf of Mexico?,” Robert Esser, May 2005, 17.

11 Ibid. 

Numerous intrastate and interstate pipelines serve

the South Central region, with resulting excess

capacity. Almost 17 Bcfd of gas was exported (after

removing imports) from the South Central region

in 2004. Estimates vary by pipeline, but average

pipeline infrastructure usage ranged from about

50% to 55%.

Source: Derived from Lippman Consulting, Inc., Platts, and pipeline company data. See

source note 9.
State of the Markets Report • June 2005 183

South Central Natural Gas Market Profile

1. Prices reflect the midpoint of day-ahead, spot transactions. All

prices reported for flow date. 

2. Prices reflect the basis or difference between the delivered price

at a downstream market hub and the price of natural gas reported at the Henry Hub for spot, day-ahead transactions.

Differences between downstream hub prices reported by Gas

Daily and the Henry Hub for every calendar flow date in a month

are averaged. 

3. Reflects near-month natural gas swap price. 

4. Trading volumes reported by Gas Daily at various market hubs

often exceed ICE reported volumes because Gas Daily may count

the same transaction twice—once from a seller’s standpoint and

once from a buyer’s standpoint. Conversely, as exchange traded

products, transactions involving two counterparties are reported

only once by ICE. 

5. Rig count based on data reported by Baker Hughes. Production

results based on analysis of trends reported by Lippman

Consulting, Inc. 

6. Data for 2003 derived from EIA files entitled

“ng_stor_sum_dcu****.xls,” where the wild card represents the

state designation. Storage activity for 2004 derived from a MS

Excel file provided by EIA, “Working Gas by State and Month –

EIA 2004.xls.”

7. Storage: “Natural Gas Annual 2003,” Movements and Storage –

Table 14, EIA. Proved reserves: file

“ng_enr_dry_a_EPG0_R11_Bcf_a.xls”, Dry Natural Gas Proved

Reserves as of December 31, 2003. File as of April 1, 2005.

Totals may not equal sum of components due to independent

rounding. Proved reserve estimates exclude Federal offshore dry

proved reserves, which amount to 22,570 Bcf. 

8. “Deepwater Gulf of Mexico 2005: Interim Report of 2004 highlights,” OCS Report, MMS 2005-023, May 2005, Appendix C, and

Bentek Energy, Bentek Raw Prod Data.xls, April 21, 2005.

9. Operationally available capacity data bases from Platts GasDat;

operationally available capacity information from pipeline company informational postings; “Monthly Pipeline Reports” and

“Monthly Regional Capacity Reports” from Lippman Consulting,

Inc; and OMOI analysis. 

Disclaimer: This report contains analyses, presentations, and 

conclusions that may be based on or derived from the data sources

cited, but do not necessarily reflect the positions or recommendations of the data providers. 

Source notes
184 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

South Central Natural Gas Market Profile
Although the Southeast is the smallest regional end-use

gas market in the United States—it consumed only

15% of dry gas produced in the Lower 48 states in 2004—it

contains some of the fastest growing gas markets in the

country.1 Overall, estimated gas demand increased 5% in

2004, with the power and industrial sectors accounting for

65% of that demand. The region’s principal sources of gas

supply include fields in south and east Texas, shallow and

deepwater offshore locations, coalbed methane in the

Black Warrior Basin, as well as various onshore locations

and liquefied natural gas (LNG) terminals. Estimated gas

production within the region declined by 12%, or 56 Bcf, in

2004.

Currently, the Southeast has 163 Bcf of storage capacity,

much of it located upstream of the fastest growing markets

(i.e., Florida, Georgia, and North Carolina). The Southeast

depends heavily on natural gas deliveries from the South

Central region to meet its fuel requirements. Estimated

firm inter-regional gas deliveries from South Central to the

Southeast averaged more than 14 Bcfd in 2004.2 Most of

this gas was exported in turn to the Northeast and

Midwest. In much of the Southeast market, end-users’ gas

procurement options have been limited by regional infrastructure and a lack of market liquidity. Proposals to develop gas infrastructure, however, advanced during the year

along with improvements in trading liquidity. 

Southeast Natural Gas Market Profile

State of the Markets Report • June 2005 185

$5.93

$5.27

$5.88

$5.89

Texas Eastern

M-1 (Kosi)

Elba Island

Transco

Zone 3

Transco, Zone 5

delivered

Transco

Zone 4

TN

VA

NC

AL

SC

MS

GA

FL

South

Florida

Virginia - Carolinas

Gas Trading Points

Gas Supply Area

LNG Terminal

• Gas supply shut-ins. Hurricane

Ivan shut in 151 Bcf of gas 

supply in 2004. At one point,

the shut-ins temporarily curtailed 6.5 Bcfd, or 13%, of the

average Lower 48 gas production. Many of these shut-ins

affected the Southeast directly

or the gathering lines that

deliver gas into Southeast

pipelines. 

• Increased demand. Gas-fired

power sector demand

increased 142 Bcf (17%).

Overall gas demand rose 140

Bcf (5%). Estimated industrial

consumption remained

unchanged, despite increased

gas prices, because of strong

economic growth. 

• Increased trading volume.

Transcontinental (Transco)

Zone 5 daily trading volume

reported by Gas Daily

increased from 38,200 MMBtu

in 2003 to 90,200 MMBtu, in

part because of increased

deliveries at the Elba Island,

Ga., LNG import terminal. 

• Advanced diversification.

Gulfstream Natural Gas

increased its pipeline load 

factor to 29% on an average

annual basis. Tractebel,

Florida Power & Light, and El

Paso Corp. joined forces to

establish a prospective project

linking re-gasified LNG in the

Bahamas to south Florida via 

a new pipeline. Send-out at

the Elba Island terminal 

doubled to an average annual

level of 252 MMcfd. 

• New capacity. Several major

regional pipeline parent companies—El Paso, CrossCountry,

Duke, and Williams—brought

new capacity on line, submitted applications to build 

new capacity, and held open

seasons for future service 

commitments.

Hub Prices ($ per MMBtu)

2003 2004 5-Year

Texas Eastern M-1 (Kosi) $5.55 $5.93 $4.65

Transco Zone 3 $5.46 $5.88 $4.61

Transco Zone 4 $5.47 $5.89 $4.62

Transco Zone 5, delivered $5.82 $6.27 $5.35*

Source: Derived from Platts Gas Daily data.

* 3 year average available only

Source: Derived from Platts data.

2004 Average Daily Hub Prices ($ per MMBtu)

Focal Points for 2004
186 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Annual spot prices at key Southeast trading points—Texas Eastern

Transmission Corp. (TETCO) M1, and Transco Zones 3, 4, and

5—averaged $5.99/MMBtu in 2004, approximately $0.41/MMBtu

higher than 2003 prices.3 During 2004, daily prices at Transco

Zone 4 ranged between $4.23/MMBtu and $8.11/MMBtu. The

basis between the Henry Hub and the Southeast markets varied

between $0.08/MMBtu for the upstream Southeast points (Texas

Eastern Transmission and East Louisiana) and $0.31/MMBtu for

downstream points (Transco Z5). Typically, gas deliveries in

Transco Zone 5 reflected congestion at downstream points in the

Northeast and therefore traded about $0.20–$0.30/MMBtu above

the other points in the Southeast.

Southeast Natural Gas Market Profile

SPOT MARKETS: PRICES AND VOLUMES

Day-ahead Spot Prices Monthly Average Basis Value to Henry Hub

Source: Derived from Platts data. See source note 1. Source: Derived from Platts data. See source note 2.

Supply Disposition 2004 2003

(Bcf) (Bcf)

Total Dry Production 399 455

Production by Region

Salt Dome - AL-FL-MS 291 343

Black Warrior 107 111

Other 2 2

Other Sources of Supply (2004 Bcf)

International Supply

Imports Exports Net Imports

Canada 0 0 0

Mexico 0 0 0

LNG 96 0 96

Total 96 0 96

Interregional Pipeline Flows

Net Imports

to Midwest (2,536)

to South Central 4,928

to Northeast (687)

Total 1,704

Demand Disposition 2004 2003

(Bcf) (Bcf)

Residential 451 470

Commercial 346 341

Industrial 831 830

Power 960 818

Losses and other 176 166

Total 2,764 2,624

Key End Use Markets

Florida - FL 757 704

Virginia - Carolinas 673 635

South - MS,AL,GA,TN 1,335 1,285

Southeast Supply Demand Statistics

Source: Derived from Bentek Energy, LLC data. Note: Negative net imports are net exports.
Forward market expectations of the Transco Zone 3 basis swaps

traded within a narrow $0.06/MMBtu premium to the Henry

Hub in 2004. Financial swap volumes traded between 1,620,000

MMBtu per day (IntercontinentalExchange (ICE) and 5,000,000

MMBtu er day (Gas Daily). The average ICE financial volume

traded outstripped physical volume traded by more than 2-to-1.4

Next-month physical trading volume at Transco Zone 3 showed

a sharp decline during 2004. Whereas a high volume of frontmonth gas was often traded during the first few months of the

year, beginning in May, physical trading shifted to next-day or

intraday deals.

State of the Markets Report • June 2005 187

FINANCIAL MARKETS: PRICES AND VOLUMES

Southeast Natural Gas Market Profile

Transco Zone 3 Swaps Prices from Trade Date Transco Zone 3 Forward and Swaps Volume

Source: Derived from Bloomberg, L.P. and Nymex data. See source note 3. Source: Derived from Bloomberg L.P., ICE, and Nymex data.

Daily trading volumes at Transco Zone 3 and Texas Eastern Mt

Kosi (TETCO M1) increased from 2003. At TETCO M1, Gas Daily

reported that the average volume increased 31% to 162,000

MMBtu. At Transco Zone 3, Gas Daily reported a 21% average volume increase to 442,000 MMBtu, and ICE reported a 31%

increase to 238,000 MMBtu. In 2004, highest reported single-day

trading volumes at Transco Zone 3 occurred on July 15 (Gas Daily)

and on December 29 (ICE).

HUB POINTS: VOLUMES

Transco Zone 3 Reported Volumes Texas Eastern M1 Kosi Reported Volumes

Source: Derived from Platts and ICE data. See source note 4. Source: Derived from Platts and ICE data. See source note 4.
188 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Southeast Natural Gas Market Profile

NATURAL GAS INFRASTRUCTURE DEVELOPMENTS

The Southeast added little gas infrastructure in 2004.

TETCO’s M1 Expansion Project and Southern Natural Gas

Co.’s South System Expansion Project added 527 MMcfd of

pipeline capacity to the Southeast region. In February,

Transco placed into service Phase II of the Momentum

pipeline expansion service, increasing firm capacity on its

system in Georgia by about 52 MMcfd. FERC approved El

Paso’s Elba Island LNG expansion plans to increase send-out

by 0.5 Bcfd in the first quarter of 2006. During 2004, Gulf

LNG Energy LLC filed plans for the Port of Pascagoula LNG

Project (1.0 Bcfd) in Mississippi. 

FERC issued a certificate to the Saltville Storage project in

Smyth County, Va. When completed, the salt cavern facility

will have 5.8 Bcf of gas capacity and deliverability of 550

MMcfd. The facility is connected to the East Tennessee

Natural Gas Pipeline, and the expansion is expected to

improve gas supply flexibility and reliability to customers in

eastern Tennessee and southwestern Virginia. AGL Resources

bought Saltville from NUI Corp. on November 30. 

In July, Gulfstream began construction on its Phase II, 30-inch

diameter, 110-mile mainline lateral to eastern Florida. The

expansion, completed in February 2005, enables Gulfstream to

deliver natural gas to Florida Power & Light’s Martin gas-fired

power plant in Indiantown, Florida.5 Florida Gas

Transmission (FGT) announced in December its Phase VII

Expansion Open Season for service beginning in mid-2007.

FGT executed a precedent agreement with Progress Energy to

serve Progress Energy’s Hines generating facilities near

Tampa. On December 21, Southern Natural Gas sought use of

the Commission’s National Environmental Policy Act PreFiling Process for the Cypress Pipeline Project, a proposed 165-

mile, 24-inch diameter pipeline that would link LNG gas

receipts at Elba Island with end-users in Florida.

Storage

LNG

Pipeline

In-Service

Filed

Approved

Directional Flow

3 6

5

4

2

7

1

1. M-1 Expansion Project

2. South System Expansion Project

3. Phase II Momentum Expansion Project

4. Saltville Storage Project

5. Clean Energy Project

6. Elba Island Georgia Expansion

7. Compass Port

This map numbering system corresponds to the 

following three charts on pipeline, storage, and

LNG projects.

PROJECT DEVELOPMENT
State of the Markets Report • June 2005 189

Southeast Natural Gas Market Profile

Company Project Name Capacity Capital Cost Status Year From-To 

(MMcfd) (Millions)+ Certificated State

1 -Texas Eastern Transmission LP M-1 Expansion 197 $66 In-Service 05/04 2004 MS-AL

Phase 1 In-Service 11/03

2 -Southern Natural Gas Company South System Expansion 330 $229 Phase 2 In-Service 07/04 2004 LA-GA

3 -Transcontinental Gas Pipeline Phase II Momentum Expansion 52 $189 In-Service 02/04 2004 GA-GA

Total 579 $484

Pipeline Projects

Company Project Name Capacity Deliverability Capital Cost Status Year State

(Bcf) (MMcfd) (Millions)+ Certificated

4 -Saltville Gas Storage Co, LLC Saltville Storage 5.8 550 $96 Approved 2004 VA

Total 5.8 550 $96

Storage Projects

Company Project Name Capacity Send-Out Capital Cost Status Year State 

(Bcf) (Bcfd) (Millions)+ Certificated

5 -Gulf LNG Energy, LLC Clean Energy Project 6.8 1.0 $450 Filed 2004 TBD MS

6-El Paso/ Southern LNG Elba Island Georgia Expansion 3.3 0.5 $86 Approved 2004 GA

7 -ConocoPhilips Compass Port* 6.3 1.0 $700 Filed 2004 TBD AL

Total 16.4 2.5 $1,236

LNG Projects

Source: FERC Office of Energy Projects. * Coast Guard jurisdictional facility. +Captial cost figures are estimates.

PIPELINE UTILIZATION

Transcontinental is the largest pipeline serving the Southeast, Average Annual Gas Flows (MMcfd)

both in capacity and in volumes transported, though much of

the gas it moves is delivered farther up the East Coast.

Southeast pipelines that transport gas on to the Northeast and

Midwest averaged 80% and 65% load factors, respectively.

Several pipelines serve primarily the Southeast itself (including

Alabama, Mississippi, Georgia, and the Florida panhandle)—

Southern Natural, Texas Eastern’s M1 line, and Gulf South.

They all have relatively low load factors, ranging from 42% to

65%. Two pipelines mainly serve peninsular Florida—Florida

Gas and Gulfstream. Customers use almost all the capacity on

Florida Gas because of its lower rates. They use Gulfstream for

supplementary supply, resulting in a much lower load factor.

Source: FERC Office of Energy Projects. +Captial cost figures are estimates.

Source: FERC Office of Energy Projects. +Captial cost figures are estimates.

Source for chart on right: Derived from Lippman Consulting Inc. and Platts 

databases.
Gas fields in south and east Texas, in Louisiana, in shallow and

deepwater offshore locations, and in the Black Warrior Basin

account for much of the region’s supply. LNG imports through

the Elba Island re-gasification facility more than doubled in 2004

to almost 100 Bcf, and El Paso plans to complete an expansion

project in 2005 that will increase capacity to 3.3 Bcf. Transco,

TETCO, and Southern Natural interstate pipelines serve the

region, but Transco remains the principal transporter for customers located from Georgia to Virginia. Regional dry proved

reserves exceed 6,800 Bcf.

In 2004, the Southeast region had 163 Bcf of storage capacity distributed among 13 storage facilities. Mississippi accounted for 144

Bcf, or nearly 88%, of regional gas storage capacity. High-deliverability salt cavern storage represented nearly 32% of total regional capacity. Satellite LNG storage facilities located throughout the

Southeast added about 23 Bcf of capacity to the regional storage

mix. Salt cavern storage contributed about 3.6 Bcfd to regional gas

deliverability. 

In February, inventories stood near 30 Bcf, approximately the 5-

year average level for that time of year. Robust injections into

storage began in March and continued through August. Regional

working gas storage levels were high during most of the

April–October injection season, averaging 5–10 Bcf above 5-year 

average levels. Net regional gas storage withdrawals occurred during early to mid-September because Hurricane Ivan temporarily

hampered Gulf Coast gas production. Working gas levels recovered, however, quickly reaching almost 71 Bcf on November 1, or

about 6 Bcf above the 5-year top of the range for the beginning of

the withdrawal season.

Regional Storage Inventory Levels

REGIONAL GAS SUPPLY

190 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Southeast Natural Gas Market Profile

Source: Derived from EIA data. See source note 5.

The Atlantic Basin had a more active season than average with

nine hurricanes, six of which were major (Category 3 or

above). The hurricanes caused an estimated $42 billion in

damage, the most costly U.S. hurricane season on record. Four

hurricanes (Ivan, Charley, Frances, and Jeanne) damaged an

estimated one in five homes in Florida. Although Ivan did not

cause the largest economic damage, it had the greatest effect on

Gulf of Mexico production because of its track through the central gulf. The other three hurricanes tracked over the east and

west coasts of Florida.

Hurricane Ivan moved through the east-central portion of the

Gulf of Mexico, making landfall near Mobile Bay, Ala., on

September 16, damaging 24 oil and gas platforms and destroying 7 platforms. Seventeen pipelines were damaged, mostly as

a result of mudslides on the Louisiana Shelf. Oil and gas companies started removing personnel from platforms on September

10 and began shutting in production on September 14. 

Significant production was shut-in for long periods of time.

Among its final Hurricane Ivan statistics, the Minerals

Management Service (MMS) reported that cumulative shut-in

natural gas production from September 11, 2004, through

December 31, 2004 was 151 Bcf, or 3.4% of yearly natural gas

production in the Gulf of Mexico. Typically, the gulf accounts

for about 22% of total domestic natural gas production.

Hurricane Ivan Shut-ins Compound an Already Tight Supply Market

Source: Derived from MMS data.
State of the Markets Report • June 2005 191

Southeast Natural Gas Market Profile

Source: Derived from EIA data. Note: Totals may not equal sum of components due to independent rounding. See source note 6.

Source for chart on right: Derived from Lippman Consulting Inc., Platts GasDat, and

pipeline company data. See source note 7.

MARKET SHARES AND CONCENTRATION

Firm Capacity Rights Share of Firm Interstate Pipeline 

Rank Firm Shipper Held (MMcf) Capacity in Florida

1 Florida Power & Light Co. 750 28.2%

2 Peoples Gas System 413 15.5%

3 Florida Power Corp 207 7.8%

4 Tampa Electric Co. 159 6.0%

5 Florida Gas Utility 103 3.9%

6 Calpine Energy Services LP 101 3.8%

7 Southern Co. Services Inc 87 3.3%

8 Tallahassee Electric & Gas Dept. 65 2.5%

9 Orlando Utlities Commission 60 2.3%

10 NUI Utilities 59 2.2%

11 All Others 654 24.6%

Total 2,659 100.0%

Florida Firm Capacity by Holding Company

Depleted Aquifer Salt Total Dry Proved

Gas/Oil Cavern Storage Reserves

Sites Capacity Sites Capacity Sites Capacity Sites Capacity 

(Bcf) (Bcf) (Bcf) (Bcf) (Bcf)

Alabama 1 3 0 0 1 82 2 11 4,301

Florida 0 0 0 0 0 0 0 0 79

Mississippi 4 103 0 0 3 41 7 144 746

Tennesse 1 1 0 0 0 0 1 1 0

Virginia 1 4 0 0 2 3 3 7 1,717

Total 7 111 0 0 6 52 13 163 6,843

Monthly gas flows into Florida averaged about 2 Bcfd in 2004.

Load factors varied significantly by interstate gas pipeline. FGT

accounted for on average about 80% of natural gas delivered to

Florida. Throughput on Gulfstream increased nearly 50% and

averaged over 300 MMcfd. 

Ownership of firm transportation rights on interstate natural gas

pipelines delivering gas into Florida remained moderately concentrated. Florida Power & Light, Peoples Gas System, Florida

Power Corp, and Tampa Electric owned 58% of the total firm

transportation delivery rights. The top 10 firm shippers retained

75% of aggregate capacity rights. Power generators dominated

firm transportation rights.

Storage and Gas Reserves Overview

Source: Derived from analysis of Platts GasDat data. See source note 8. One million Btu assumed to equal 1 Mcf.

Florida Pipelines
Source notes

192 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Southeast Natural Gas Market Profile

1. Prices reflect the midpoint of day-ahead spot transactions. All

prices reported for flow date. 

2. Prices reflect the basis or difference between the delivered

price at a downstream market hub and the price of natural gas

reported at the Henry Hub for spot, day-ahead transactions.

Differences between downstream hub prices reported by Gas

Daily and the Henry Hub for every calendar flow date in a month

are averaged. 

3. Reflects near-month natural gas swap price. 

4. Trading volumes reported by Gas Daily at various market hubs

often exceed ICE reported volumes because Gas Daily may

count the same transaction twice—once from a seller’s standpoint and once from a buyer’s standpoint. Conversely, as

exchange traded products, transactions involving two counterparties are reported only once by ICE. 

5. Data for 2003 derived from EIA files entitled

“ng_stor_sum_dcu****.xls,” where the wild card represents the

state designation. Storage activity for 2004 derived from a MS

Excel file provided by EIA, “Working Gas by State and Month –

EIA 2004.xls.”

6. “Natural Gas Annual 2003,” Movements and Storage – Table 14,

EIA. Proved reserves: file “ng_enr_dry_a_EPG0_R11_Bcf_a.xls,”

Dry Natural Gas Proved Reserves as of December 31, 2003, EIA.

File as of April 1, 2005. 

7. Operationally available capacity data bases from Platts GasDat;

operationally available capacity information from pipeline company informational postings; “Monthly Pipeline Reports” and

“Monthly Regional Capacity Reports” from Lippman Consulting,

Inc; and OMOI analysis. 

8. Uses the first quarter 2005 index of customers. Excludes firm

natural gas storage contracts. Only includes natural gas contracts with firm deliveries into Florida. 

Disclaimer: This report contains analyses, presentations, and 

conclusions that may be based on or derived from the data

sources cited, but do not necessarily reflect the positions or 

recommendations of the data providers. 

1. OMOI’s definition of the Southeast market includes three subregions: the

South (Alabama, Georgia, Mississippi, and Tennessee), Florida, and

Virginia/Carolinas (North Carolina, South Carolina, and Virginia). 

2. Bentek estimates that about 10 Bcfd of firm interstate natural gas is

exported from the Southeast to the Northeast and the Midwest. 

3. These trading points are located as follows: Transco Zone 3, sometimes

referred to as Station 65, includes the delivery areas between Mississippi

and Alabama; Transco Zone 4 includes points downstream of Station 65

to the Georgia/South Carolina border; Transco Zone 5 includes South

Carolina, North Carolina, and Virginia; and TETCO M1 is the first market

zone on Texas Eastern’s system and starts in central Mississippi at

Kosciusko, Miss. 

4. Excludes swap trades executed by voice brokers and other over-thecounter exchanges. OMOI believes trading volume by voice brokers

accounts for a sizable share of swap transactions. 

5. As a result, about two-thirds of Gulfstream’s capacity has been sold under

long-term firm transportation contracts. 

Endnotes
The West1 was the only regional market that produced

and consumed more gas in 2004 than in 2003. Estimated

gas consumption grew by 0.2 Tcf, or 5%, to 4 Tcf in 2004 and

accounted for 20% of U.S. total consumption in the Lower 48

states. California, the largest market in the West, accounted

for 2.4 Tcf (55%) of total estimated consumption. More than

half of the estimated growth in regional gas demand came

from the power-generation sector. As the leading consuming

sector, power accounted for nearly 1.4 Tcf (about a third) of

regional gas consumption. Diverse gas resources from western Canada (Alberta and British Columbia), the San Juan

Basin, the Permian Basin, the Rocky Mountains, and

California supply the region. Estimated gas production in the

West increased 62 Bcf (1%) in 2004. So did Canadian gas

imports (about 200 MMcfd, or 8%).2 Record drilling in

Colorado and Wyoming in 2004 highlighted the growing role

of Rocky Mountain gas in the U.S. production outlook.3

Developers also are attempting to add liquefied natural gas

(LNG) as a substantial component of incremental supply in

California and the Southwest (probably via Mexico). The

western market contains 1.3 Tcf, or about 16%, of total U.S.

storage capacity. 

Western Natural Gas Market Profile

State of the Markets Report • June 2005 193

OR

CA

WA

NV

NM

AZ

CO

UT

MT

WY ID

Southwest

California

Northwest

Mountain

Gas Trading Points

Gas Supply Area

LNG Terminal

$5.16

$5.19

$5.75

$5.15

$5.34

$5.18

El Paso, Permian Basin

Stanfield

Cheyenne Hub

Sumas

Kern River,

Opal Plant

El Paso, 

San Juan Basin

$5.35

Malin

$5.24

PG&E 

Citygate

$5.51

SoCal Gas

• Average annual gas prices at

key Rocky Mountain production market hubs rose at

least 14%—Cheyenne Hub

(29%), Kern River, Opal plant

(20%), and El Paso/San Juan

Basin (14%). New take-away

pipeline capacity was added

to the Rocky Mountain region

in 2003–04 raising gas prices

to regional producers by linking new production fields

with growing, downstream

markets. Wholesale gas price

increases at most downstream end-use markets in

the West rose 5%–10%.

• Interstate pipelines placed

into service provided more

than 1.5 Bcfd of new capacity, 

valued at more than $600

million; incremental pipeline

improvements increased

access to new gas fields and

enhanced the reliability of

traditional transportation corridors. 

• Gas production trends were

mixed. Preliminary estimates

indicate a 1.3% increase in

2004. New production areas

in the Green River and UintaPiceance basins spearheaded

a 91-Bcf growth in dry gas

production, whereas more

mature areas, such as the

Permian, declined by 9 Bcf.4

Wyoming and Colorado set

drilling records in 2004,

according to state-specific 

records going back to 1987.

• Commercialization of LNG

moved slowly. Developers

filed plans with FERC and the

U.S. Coast Guard to build

four new LNG import facilities. By year end, Sempra

Energy Global Enterprises’s

LNG project in Ensenada,

Mexico—Energia Costa

Azul—had met many of the

requirements to bring its terminal on line: manage crossjurisdictional regulatory oversight, obtain financing,

acquire liquefaction rights,

secure shipping rights, negotiate capacity deals, and

obtain permits. 

• An unplanned outage at the 

San Onofre nuclear plant on

November 19 highlighted the

benefits of regional fuel

diversity and led to improved

gas and electric industry

coordination. High, unanticipated gas-fired consumption

due to the outage resulted in

extremely low line-pack on

San Diego Gas & Electric’s

30-inch diameter line.

However, SDG&E reinforced

system pressures by reimporting gas flowing

through the North Baja

Pipeline and downstream

pipelines in Mexico—the

Gasoducto Bajanorte and the

Transportadora de Gas

Natural systems—back into

the United States.5

Source: Derived from Platts data

2004 Average Daily Hub Prices ($ per MMBtu)

Hub Prices ($ per MMBtu)

2003 2004 5-Year 2003 2004 5-Year

Cheyenne Hub $4.00 $5.16 $3.77 PG&E citygate $4.83 $5.24 $4.35

El Paso, San Juan Basin $4.56 $5.18 $3.95 Stanfield $5.23 $5.75 $5.16

El Paso, Permian Basin $5.07 $5.34 $4.30 SoCal Gas $5.08 $5.51 $5.57

Kern River, Opal Plant $4.31 $5.19 $3.72 Sumas $4.69 $5.15 $4.24

PG&E Malin $4.90 $5.35 $4.73

Focal Points for 2004

Source: Derived from Platts data.
194 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Spot gas prices generally increased more in the West than in the

East, but price changes varied by market. The most significant

increases in average annual gas prices were reported in upstream

supply basins benefiting from recent pipeline capacity expansions—at the Cheyenne Hub (29% expansion) and at the Kern

River/Opal plant (20% expansion). New pipeline capacity

enabled more gas from the Rocky Mountains to flow to markets

in the West and the Midcontinent, resulting in greater price integration with western and eastern end-use markets. Prices

increased more moderately in most other western markets.

Average annual gas prices in major western end-use markets—

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

at Malin, and citygates—increased 8%–11%. Western gas prices

paralleled Gulf Coast price increases in October caused by hurricane-related production shut-ins and record crude oil price

increases.

Western Natural Gas Market Profile

SPOT MARKETS: PRICES AND VOLUMES

Day-ahead Spot Prices

0

2

4

6

8

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

NovDec

Prices ($/MMbtu)

El Paso San Juan

Kern River- Opal

SoCal

Sumas

Monthly Average Basis Value to Henry Hub

-1.50

-1.00

-0.50

0.00

0.50

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Price Difference ($/MMbtu)

El Paso San Juan Kern

SoCal Sumas

Source: Derived from Platts data. See source note 1. Source: Derived from Platts data. See source note 2.

Supply Disposition 2004 2003

(Bcf) (Bcf)

Total Dry Production 4,855 4,793

Production by Region

San Juan 1,386 1,385

Green River 846 799

Permian - New Mexico 520 529

Uinta - Piceance 511 467

Other 1,591 1,523

Other Sources of Supply (2004 Bcf)

International Supply

Imports Exports Net Imports

Canada 1,024 0 1024

Mexico 0 105 (105)

LNG 0 0 0

Total 1,024 105 919

Interregional Pipeline Flows Net Imports

to Midwest (398)

to South Central (591)

Total (989)

Demand Disposition 2004 2003

(Bcf) (Bcf)

Residential 960 931

Commercial 524 547

Industrial 1,196 1,111

Power 1,393 1,276

Losses and Other 229 219

Total 4,302 4,085

Key End Use Markets

California - CA 2,369 2,248

Northwest - WA, OR, ID 570 538

Mountain - CO, UT, WY, MT 667 666

Southwest - NV, AZ, NM 696 634

Supply Demand Statistics

Source: Derived from Bentek Energy, L.L.C. data. Note: Negative net imports are net exports.
Average annual basis values at liquid trading points throughout

the West ranged between -$0.34/MMBtu and -$0.70/MMBtu.

Many major western trading points traded at discounts of greater

than $1/MMBtu to the Henry Hub during October when

Henry’s gas prices climbed significantly because of hurricanerelated shut-ins and oil market price increases. The SoCal swap

prices dropped consistently during the year for trade dates in

March, June, September, and October. Actual SoCal basis closely

tracked expectations, averaging -$0.36/MMBtu. Trading volumes

reported by platform show that New York Mercantile Exchange

(Nymex) and IntercontinentalExchange (ICE) financial products

ranged from a low of 51,000,000 MMBtu and 10,000,000 MMBtu,

respectively, in January to a maximum of 126,000,000 MMBtu

(September) and 40,000,000 MMBtu (November), respectively.

ICE physical trades were minimal throughout the year.

State of the Markets Report • June 2005 195

FINANCIAL MARKETS: PRICES AND VOLUMES

Western Natural Gas Market Profile

SoCal Swaps Prices from Trade Date SoCal Forward and Swaps Volume

-0.6

-0.5

-0.4

-0.3

-0.2

-0.1

0

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

NovDec

Near-Month Swap Prices ($/MMbtu)

December 03

March 04

June 04

September 04

October 04

0

40,000

80,000

120,000

160,000

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

NovDec

Volume (1000's MMBtu)

ICE Physical

ICE Financial

Nymex

Source: Derived from Nymex data. See source note 3. Source: Derived from ICE, Bloomberg, L.P., and Nymex data.

Daily trading activity at market hubs in the West rose markedly in

2004. For example, average daily volumes reported by Platts Gas

Daily at SoCal jumped 96%, from 291,000 MMBtu in 2003 to

570,000 MMBtu in 2004; similarly, ICE-reported volumes at

SoCal Gas soared 146%, from 122,000 MMBtu to 302,000

MMBtu. Trading volumes reported at the Kern River/Opal

increased 27%, from 66,000 MMBtu to 314,000 MMBtu (Gas

Daily) and 17%, from 25,000 MMBtu to 173,000 MMBtu (ICE).

HUB POINTS: VOLUMES

SoCal Reported Volumes

0

300

600

900

1,200

Jan

FebMar

Apr

May

Jun

Jul

AugSep

Oct

NovDec

Volume (000's MMBtu/d)

Gas Daily

ICE

Kern River Reported Volumes

0

200

400

600

800

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

NovDec

Gas Daily

ICE

ICE

Source: Derived from Platts and ICE data. See source note 4. Source: Derived from Platts and ICE data. See source note 4. 
196 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Western Natural Gas Market Profile

NATURAL GAS INFRASTRUCTURE DEVELOPMENTS

Company Project Name Capacity Capital Cost Status Year From-To 

(MMcf/d) (Millions)+ Certificated State

1-Northwest Everett Delta Lateral 113 $24 In-Service 11/04 2004 WA-WA 

2-Colorado Interstate Cheyenne Jumper Compressor 118 $5 In-Service 12/04 2004 CO-CO

3-TransColorado TransColorado Expansion 125 $29 In-Service 08/04 2004 CO-CO

4- Wyoming Interstate Echo Springs 116 $12 In-Service 11/04 2004 WY-WY

5- Cheyenne Plains Cheyenne Plains 560 $410 In-Service 12/04 2004 WY-KY

6- El Paso Bondad Expansion (Phase 1&2) 140 $7 In-Service 03/04 2003 CO-CO

7-El Paso Line No. 2000 Power Up Phase I 120 $81 In-Service 02/04 2003 TX-AZ

8-El Paso Line No. 2000 Power Up Phase II 100 $54 In-Service 04/04 2003 TX-AZ

9-El Paso Line No. 2000 Power Up Phase III 100 $39 In-Service 06/04 2003 TX-AZ 

10- Pinnacle Hobbs Lateral Expansion 42 $1 In-Service 03/04 2003 NM-NM

11- Questar Southern System Expansion 102 $55 Filed 2004 2005 UT-UT

12- Cheyenne Plains Cheyenne Plains 2005 Expansion 170 $8 Approved 2004 CO-CO

Total 1,806 $725

Storage

LNG

Pipeline

I n-Service

Filed

Approved

Directional Flow

17 7-9

19

2

10

6 3 5

11

1

14

15 16

18

13

5

4 12

1. Everett Delta Lateral Project

2. Cheyenne Plains Jumper Compressor

3. TransColorado Expansion Project

4. Echo Springs Project

5. Cheyenne Plains Pipeline Project

6. Bondad Expansion Project

7. Line No. 2000 Power Up Phase I

8. Line No. 2000 Power Up Phase II

9. Line No. 2000 Power Up Phase III

10. Hobbs Lateral Expansion Project

11. Southern System Expansion Project

12. Cheyenne Plains 2005 Expansion

13. Cheyenne Market Center Expansion 

14. Long Beach LNG Terminal

15. Clearwater Port

16. Cabrillo Port

17. Energia Costa Azul

18. Terminal GNL Mar Adento de Baja, California

19. Sonora Pacific LNG Project

This map numbering system corresponds to the following

three charts on pipeline, storage, and LNG projects. 

PROJECT DEVELOPMENT

Pipeline Projects

Source: FERC Office of Energy Projects. + Capital cost figures are estimates.
State of the Markets Report • June 2005 197

Western Natural Gas Market Profile

Company Project Name Capacity Deliverability Capital Cost Status Year State

(Bcf) (MMcf/d) (Millions)+ Certificated

13 -Kinder Morgan Interstate Cheyenne Market Center In-Service

Gas Transmission Expansion Project 6.5 68 $27 06/04 2003 CO, NE

Total 6.5 68 $27

Storage Projects

Company Project Name Capacity Send-Out Capital Cost Status Year State 

(Bcf) (Bcf) (Millions)+ (Bcfd) Certificated

14 -Sound Energy Solutions Long Beach 3.5 0.7 $400 Filed 2004 TBD CA

15 -Crystal Energy Clearwater Port* 0 0.5 $160 Filed 2004 TBD` CA

16- BHP Billington Cabrillo Port* 6.0 1.5 $550 Filed 2004 TBD CA

17- Sempra & Shell Energía Costa Azul** 6.8 1.0 $600 Approved 2004 MX

18 -Chevron Texaco GNL Adentro de Baja*** 5.3 1.4 $650 Approved 2004 MX

19 -Sonora Pacific Sonora Pacific 6.8 1.3 $500 Filed 2004 TBD MX

Total 28.4 6.4 $2,860

LNG Projects

Source: FERC Office of Energy Projects and California Energy Commission. + Captial cost figures are estimates.

* Coast Guard jurisdictional facilities (all others are FERC jurisdictional). **All major permits obtained in Mexico. *** Environmental permit granted in Mexico.

Source: FERC Office of Energy Projects. + Captial cost figures are estimates.

Ten pipeline projects accounting for 1.5 Bcfd of incremental

capacity began commercial service in 2004 in the western market. FERC approved one pipeline expansion adding 170 Mcfd.

The Cheyenne Hub added 6.5 Bcf of storage capacity and 66

MMcfd of deliverability. 

Developers submitted applications to build four LNG import

terminals in the West, totaling four Bcfd in potential send-out.

Infrastructure developers held numerous open seasons in 2004

to assess whether shippers wanted access to new conventional

and LNG supply sources.

El Paso Natural Gas Co. and its customers reached a final settlement on reallocation of capacity rights in August 2004.

Customers secured firm, point-to-point rights similar to traditional rights available on other pipelines. The reallocation has improved service and affected how customers buy

and sell both financial and physical gas in the Southwest

market (including California). Responding to FERC’s directives, El Paso changed its capacity allocation, requiring fullrequirements customers to convert to contract-demand

service. This change meant that the same type of tariff was

levied on all customers and also required them to switch

from systemwide to specific-receipt rights. As a result, firm

service on the El Paso system has become more reliable and

capacity is allocated to those customers valuing it most. 

El Paso Capacity Allocation Problem Settled
198 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Western Natural Gas Market Profile

Source: Derived from EIA data. See source note 6.

Storage and Gas Reserves Overview

Depleted Aquifer Salt Total Dry Proved 

Gas/Oil Cavern Storage Reserves

Sites Capacity Sites Capacity Sites Capacity Sites Capacity 

(Bcf) (Bcf) (Bcf) (Bcf) (Bcf)

California 8 446 0 0 0 0 8 446 2,450

Colorado 9 101 0 0 0 0 9 101 15,436

Montana 5 374 0 0 0 0 5 374 1,059

New Mexico 2 79 1 5 0 0 3 84 17,020

Oregon 5 24 0 0 0 0 5 24 0

Utah 1 118 2 12 0 0 3 129 3,516

Washington 0 0 1 40 0 0 1 40 0

Wyoming 7 104 1 10 0 0 8 114 21,744

Total 37 1,246 5 67 0 0 42 1,312 61,225

REGIONAL GAS SUPPLY

Much of the region’s supply originates in the Southwest and in

the Rocky Mountains of the United States and Canada.

Domestic production of more than 4,800 Bcf accounts for more

than 80% of regional supply with the other 20% coming from

Canada. Conventional and nonconventional (coalbed

methane) gas production comes from California; the western

Canadian Sedimentary Basin; the San Juan Basin; the Permian

Basin; the Powder River Basin; the Raton Basin; and the

Piceance, Uintah, and Green River basins in the central Rocky

Mountain area. An increasingly important source of production, coalbed methane from the San Juan Basin and various

Rocky Mountain basins, totaled more than 4 Bcfd in third quarter 2003.6 Proved dry gas reserves in the region total about

61,200 Bcf.

More than 1.3 Tcf of storage capacity at 42 sites is distributed

throughout the West. Market participants use a mix of storage

facilities located in or near the production basins in the Rocky

Mountain and market-area storage in California, Oregon, and

Washington. Most of the regional storage capacity (72%) is

located in California, Montana, and Utah. Depleted reservoir

storage accounts for 1.2 Tcf of the total regional capacity. New

techniques enable storage operators to increase the storage

capacity, deliverability, and cycling of some new and existing

depleted reservoir fields. Examples of multi cycle, high-deliverability storage facilities in the West include the Lodi (17 Bcf)

and Wild Goose (17 Bcf) facilities in California and the Mist (14

Bcf) facility in Washington. In addition, the West has 4.5 Bcf of

regional, satellite LNG storage capacity to augment retail gas

supply flexibility.

Working gas inventory at the start of the injection season was

184 Bcf, nearly 20 Bcf below the 5-year average (214 Bcf), but

still within the average inventory range during the previous 5

years. Winter weather in 2003–04 was typical; actual cumulative heating-degree days reflected 96% of normal levels. Warm

summer weather, however, resulted in cumulative coolingdegree days that were 111% of normal levels. Increased cooling

consumption, however, did not dampen storage injections;

working gas inventories equaled the 5-year average (about 384

Bcf) by the start of the withdrawal season.

Aggregate California storage operations in 2004 remained in

line with operations in 2003. Systemwide, PG&E and SoCal

Gas injected 286 MMcfd of gas into storage from April through

October, about 6 MMcfd less in 2004 than in 2003. However,

an equivalent 6 MMcfd increase in injections at the independently owned and operated Lodi and Wild Goose facilities offset

this decline.

Regional Storage Inventory Levels

0

50

100

150

200

250

300

350

400

450

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

NovDec

Working Gas Storage Inventory (Bcf)

5-year

Range

2004

Source: Derived from EIA data. See source note 5.
Overall, ownership of firm receipt point capacity rights 

measured across all interstate pipelines in the Wyoming market

was not concentrated. However, ownership of firm transportation capacity rights on individual pipelines in the West was

highly concentrated. A single shipper owned 50% or more of

firm receipt point rights on the following pipelines: Questar

(72%), MIGC (100%), TransColorado (59%), Overthrust

(100%), Williston Basin (96%), and Southern Star (50%). 

State of the Markets Report • June 2005 199

Western Natural Gas Market Profile

MARKET CONCENTRATION

Major Pipeline Capacity Owners in California

Rank Company Share Capacity 

(MMcf)

1 Sempra Energy Global Enterprises 20.7% 1,721

2 PG&E Corp 11.6% 964

3 Southwest Gas Corp 5.9% 491

4 Chevron Corp 4.2% 347

5 Reliant Energy, Inc 4.6% 300

6 BP plc 3.5% 289

7 Calpine Corp 3.3% 277

8 Sierra Pacific Resources 3.2% 266

9 Duke Energy Corp. 3.0% 251

10 Royal Dutch Petroleum Co 2.1% 174

Source: Derived from Platts data. See source note 9. One million Btu assumed to

equal 1 Mcf.

Principal Capacity Owners by Pipeline 

Northwest Questar Wyoming Kern River Colorado Wyoming Est Market

Customer Pipeline Interstate Interstate Pipelines Share (%)

(MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf)

1 Questar Corp 3 1790 6 53 0 2,113 15%

2 The Williams Companies Inc 61 30 303 84 235 906 7%

3 Puget Energy Inc 777 0 0 0 0 777 6%

4 Xcel Energy Inc 0 0 40 0 665 711 5%

5 El Paso Corp 0 188 333 79 0 600 4%

6 Encana Corp 0 20 10 0 183 511 4%

7 Northwest Natural Gas Co 500 0 0 0 0 500 4%

8 BP plc 0 35 272 72 25 474 3%

9 Cascade Natural Gas Corp 412 0 0 0 0 412 3%

10 MDU Resources Group, Inc 0 0 0 0 0 404 3%

Top Est % of Top Est % of Top Est % of

Pipeline Customers Market share Customers Market Share Customers Market Share

1 Northwest Pipeline Co Puget Energy, Inc 25 Northwest Natural 16 Cascade Natural Gas 14

2 Questar Corp Questar Corp 72 El Paso Corp 8 Dominion Resources 4

3 Wyoming Interstate El Paso Corp 16 Williams Co 14 BP 13

4 Kern River Reliant 12 Southwest 11 Los Angeles Dept Water 9

5 Colorado Interstate Xcel Energy 41 Williams Co 15 Encana Corp 11

6 Southern Star Southern Union 50 Oneok 16 Duke Energy Corp 10

7 Kinder Morgan Kinder Morgan 33 Oneok 30 Northwest Corp 12

8 TransColorado Encana 59 Williams Co 28 Western Gas Resources 10

9 Willston Basin MDU 96 CHS Inc 1 Covana 1

10 Overthrust Questar Corp 100

11 MIGC Inc Western Gas Resources 100

Source: Derived from Platts data. See source note 8.

Source: Derived from Platts data. See source note 7. One Million Btu assumed to equal 1 Mcf.

Top 3 Owners of Wyoming Pipeline Capacity
-

500

1,000

1,500

2,000

2,500

3,000

3,500

El Paso Natural Gas

- San Juan

Gas Transmission Northwest - Kingsgate

Kern River Transmission

Northwest Pipeline - Sumas

Trailblazer

Transwestern Gas Pipeline - San Juan

El Paso Natural Gas

- Permian

Northwest Pipeline - West

TransColorado

Average Unscheduled Flow

Average Scheduled Flow

200 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Western Natural Gas Market Profile

PIPELINE UTILIZATION

Average Annual Gas Flows (MMcfd)

Source: Derived from Lippman Consulting Inc., Platts and pipeline company data.

See source note 11.

Average monthly natural gas deliveries by interstate pipelines

into California increased about 590 MMcfd, or 9%, to 7,100

MMcfd in 2004. Pipeline market shares were as follows: El

Paso (33% ), Transwestern (25%), Gas Transmission Northwest

(22%), Kern River (20%), and Southern Trails (1%). Annual

California consumption has two peaks, one each in winter and

summer. Gas use is somewhat less seasonal than in other markets. Ownership of firm interstate natural gas transportation

service rights by end-users in California is not concentrated.

The major LDCs—Sempra Utilities Group7 and PG&E Corp.—

owned 33% (2.7 Bcfd) of firm capacity rights on pipelines delivering natural gas into California.

Pipeline Deliveries into California (MMcfd)

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

Jan

FebMar

Apr

May

Jun

Jul

Aug

Sep

Oct

NovDec

El Paso Transwestern GTN Kern River Southern Trails

Source: Derived from Lippman Consulting, Inc. data. See source note 10.

MARKET SHARES

The largest pipelines serving major western markets are El Paso

(from the San Juan and from the Permian Basin), Northwest

(importing from Canada), and Kern River (delivering from

southwestern Wyoming). Customers use most of the capacity

on most western pipelines. An exception is the El Paso leg from

the Permian Basin. Much of the Permian Basin’s gas flows to

higher-priced regions in the East.

Estimated western gas pipeline utilization averaged 75% in

2004, the highest of any gas region.8 Customers bought comparatively low-cost gas in the Rocky Mountain region and delivered it through an expanded network of gas pipelines. Average

annual load factors were at least 89% on Kern River,

TransColorado, Transwestern San Juan, and El Paso San Juan. 
State of the Markets Report • June 2005 201

Western Natural Gas Market Profile

1. Prices reflect the midpoint of day-ahead, spot transactions. All

prices reported for flow date. 

2. Prices reflect the basis or difference between the delivered price

at a downstream market hub and the price of natural gas reported at the Henry Hub for spot, day-ahead transactions.

Differences between downstream hub prices reported by Gas

Daily and the Henry Hub for every calendar flow date in a month

are averaged. 

3. Reflects near-month natural gas swap price. 

4. Trading volumes reported by Gas Daily at various market hubs

often exceed ICE reported volumes because Gas Daily may count

the same transaction twice—once from a seller’s standpoint and

once from a buyer’s standpoint. Conversely, as exchange traded

products, transactions involving two counterparties are reported

only once by ICE. 

5. Data for 2003 derived from EIA files entitled

“ng_stor_sum_dcu****.xls,” where the wild card represents the

state designation. Storage activity for 2004 derived from a MS

Excel file provided by EIA, “Working Gas by State and Month –

EIA 2004.xls.”

6. Storage: “Natural Gas Annual 2003,” Movements and Storage –

Table 14, EIA. Proved reserves: file

“ng_enr_dry_a_EPG0_R11_Bcf_a.xls”, Dry Natural Gas Proved

Reserves as of December 31, 2003, EIA. File as of April 1, 2005.

Totals may not equal sum of components due to independent

rounding. 

7. Represents the most significant owners of firm interstate natural

gas pipeline receipt point rights (as measured in MMcfd) in

Wyoming, Northwestern Colorado, and Northeastern Utah

across all FERC-jurisdictional pipelines in this market. 

8. Comprises the top three customers (as measured in MMcfd) on

individual interstate natural gas pipelines with receipts in

Wyoming, northwestern Colorado, and northeastern Utah. 

9. Represents firm interstate pipeline delivery rights into California

by pipeline customer. The following pipelines were included in

the analysis: Transwestern, Kern River, El Paso, GTN Northwest,

and Tuscarora Gas Transmission and Southern Trails. 

10. Average monthly natural gas deliveries into California on interstate natural gas pipelines. Excludes volumes transported on

the North Baja Pipeline. 

11. Operationally available capacity databases from Platts GasDat;

operationally available capacity information from pipeline company informational postings; “Monthly Pipeline Reports” and

“Monthly Regional Capacity Reports” from Lippman Consulting,

Inc; and OMOI analysis. 

Disclaimer: This report contains analyses, presentations, and 

conclusions that may be based on or derived from the data sources

cited, but do not necessarily reflect the positions or recommendations

of the data providers. 

Source notes

1. OMOI defines the gas market in the West to include 11 states in 4

subregions: California, the Southwest (Arizona, Nevada, and New

Mexico), the Pacific Northwest (Washington, Oregon, and Idaho),

and the Mountain region (Montana, Wyoming, Colorado, Utah). 

2. The growth in net imports was only 150 MMcfd (6%) after

accounting for increased gas exports to Mexico.

3. According to the U.S. Geological Survey, Montana, Wyoming,

Colorado, and Utah together account for 26% of total U.S. gas

reserves. 

4. Bentek Energy LLC estimated natural gas consumption data when

the Energy Information Administration state-level gas consumption data were unavailable. Also, Bentek estimated natural 

gas production, international imports and exports, and firm 

inter-regional interstate gas transfers. Bentek used natural gas

production data from state agencies, when available. 

5. GBN is a 145-mile natural gas transportation pipeline that links

gas receipts from the North Baja Pipeline at Ogilby, Calif., with

deliveries into the TGN Pipeline near Tijuana in Baja California,

Mexico. Sempra Pipelines & Storage built this 30-inch-diameter

pipeline with capacity of 500 MMcfd; it began operating in

September 2002. TGN is a 23-mile, 30-inch-diameter pipeline that

began supplying natural gas from the United States-Mexico border

near San Diego to the Presidente Juárez power plant in Rosarito,

Baja California, in summer 2000.

6. Lippman Consulting, Inc., Lower-48 States Coalbed Methane 3rd

Quarter 2004 Production Report, April 19, 2005.

7. Sempra is the holding company for SoCal Gas and San Diego Gas

& Electric.

8. OMOI analysis of average annual deliveries as measured on the

following pipelines: El Paso Natural Gas—San Juan, Gas

Transmission Northwest—Kingsgate, Kern River Transmission,

Northwest Pipeline—Sumas, Trailblazer, Transwestern Gas

Pipeline—San Juan, El Paso Natural Gas—Permian, Northwest

Pipeline—West, and TransColorado.

Endnotes
202 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Western Natural Gas Market Profile
OTHER ENERGY MARKETS IN 2004

State of the Markets Report • June 2005 203

This State of the Markets Reportcontains profiles of 7 markets and other related factors that 

affect electric and natural gas markets: Coal, Demand Response, Emissions Allowances, 

Energy Debt and Equity, Oil, Weather, and Wind.
204 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Other Energy Markets National Overview

OVERVIEW

The profiles cover 7 areas that have important implications for natural gas and electric 

power markets:

Coal. Prices for eastern coal rose by as much as 69 percent during the year and contributed significantly to the

regional pattern of electric power price changes.

Demand Response. Electric power markets have little price responsive demand, the lack of which can create

price spikes. During 2004, mild summer weather reduced responses in price-sensitive programs, but more 

sophisticated technologies began to emerge.

Emissions Allowances. During 2004, emissions allowance prices rose rapidly. This added to the upward 

pressure on electric power prices in regions dependent on coal, especially from the East. Allowances can add as

much as about $20 per MWh to the running cost of an unscrubbed coal plant.

Energy Debt and Equity. During 2004, the energy industry recovered a degree of financial health, compared

with other years, as the cost of borrowing went down and stock prices rose more than the Standard and Poor’s 500

index.

Oil. Global oil markets saw significant price increases in 2004 as well. This put continuing upward pressure on all

other energy prices, including natural gas and electric power. The two most obvious factors influencing natural gas

prices are gas storage inventories and global oil prices.

Weather. Weather was moderate during 2004. The winter of 2003-2004 was 6 percent warmer than the year

before. The summer of 2004 was the ninth coolest on record. Two events affected energy markets during the year:

a cold snap in New England in January and Hurricane Ivan in September.

Wind. Wind has become the fastest-growing generation source. But it remains heavily dependent on government

policy (such as tax credits) at both state and national levels.
Coal is the leading fossil fuel used by U.S. power generators,

accounting for 1.93 billion MWh, or half of U.S. net generation in 2004. About 30% of U.S. generating capacity is coalfired. U.S. recoverable coal reserves totaled 271,677 million

short tons (mmst) in 2003 or about 25% of worldwide recoverable reserves.1 Total U.S. coal production increased by 3.7% to

1,112 mmst in 2004. The most prolific U.S. coal supply regions

are the Powder River Basin in the west with 38% and the

Appalachian Basin in the east with a third of U.S. coal production. Power sector consumption of coal increased slightly in

2004 to 1,015 mmst, reducing end-of-year stockpiles by 12% in

2004. Coal delivery was slowed by some constraints on

transloading facilities and on the intermodal network of rail,

barges, and trucks. Coal is the lowest-cost fossil fuel for power

generation on a dollar per MMBtu basis. Trends in 2004, however, indicated that coal prices may face increased price volatility in the future.2

Fewer companies controlled greater shares of total U.S. coal

production than a decade ago. The advance in public ownership of coal companies spurred accountability, short-term profitability, and sensitivity to Wall Street.3 International coal

demand growth and a weak dollar during 2004 contributed to a

17% increase in net coal exports.4

Coal

State of the Markets Report • June 2005 205

39,607

8,994

1.13 Northern 

PRB

60,045

11,229

0.95

Central Rockies 381,543

8,687

 0.69

 Southern PRB

40,853

9,890

1.33

Four 

Corners

30,325

6,563

2.17

Northern Lignite

53,255

6,143

 4.63

Gulf Lignite

90,688

11,300

4.27

111,333

12,541

3.41

231,102

12,234

1.58

 22,329

 11,870

 2.33

Illinois 

Basin

Northern 

Appalachian

Central 

Appalachian

Southern

 Appalachian

Ohio

23,151

12,232

5.48

Tons

Avg. Btu/Lb

Avg. Lb SO2/MMBtu

Lignite

Bituminous

Sub-Bituminious

Coal Production in the U.S.

Source: Derived from Platts data. See source note 1.

Source 2004 2003 5-Year Avg

Central Appalachia $54.2 $32.1 $35.6

Colorado/Utah $22.0 $15.0 $17.3

Illinois Basin—High Sulfur $29.1 $22.8 $24.2

Illinois Basin—Mid Sulfur $30.1 $24.8 $25.9

Northern Appalachia $45.6 $30.9 $31.3

PRB 8800 $6.6 $6.2 $6.4

Source: Derived from Bloomberg, L.P. data. 

Coal Spot Prices ($/short ton)

• Volatile spot prices. An 

imbalance between production and consumption combined with a strong international market, triggered a

69% increase in central

Appalachian coal prices in

2004.5 Coal prices increased

markedly in most coal supply

regions and generally exceeded 2001 levels. National retail

prices, however, increased

6%, on average, as customers

relied on long-term contracts.

• Continued price growth 

expectations. Futures prices

and over-the-counter forward 

market signals indicated 

sustained high coal prices. 

• Effects on power prices.

Higher coal prices translated

into higher on-peak and 

off-peak power prices in 

coal-dominated regions.

• Coal transportation 

constraints. Regional rail 

and barge bottlenecks

reduced coal deliveries to

customers and compounded

price volatility. 

Focal Points for 2004
206 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Production

U.S. coal production increased by 3.7% in 2004, despite transportation constraints. The 4.7% coal production increase in the

West outpaced a 3.4% increase in the East. Interior regional coal

production effectively remained unchanged. As a result, western

coal production accounted for a growing share of total U.S. production, slightly more than half in 2004. Appalachian mines produced less than 400 mmst of coal for the third consecutive year—

the first time this has happened since the 1970s.6 The increase in

eastern coal production was modest given the material change in

eastern coal spot prices.

Coal 

2004 Coal Prices

0

10

20

30

40

50

60

70

01/01/04

01/15/0401/29/0402/12/0402/26/0403/11/04

03/25/04

04/08/0404/22/04

05/06/0405/20/0406/03/0406/17/0407/01/0407/15/04

07/29/0408/12/0408/26/04

09/09/04

09/23/0410/07/04

10/21/04

11/04/0411/18/0412/02/04

12/16/04

12/30/04

$ per short ton

Northern Appalachia PRB 8800 Central Appalachia

Illiniois Basin High Sulfur Illinois Basin Medium Sulfur Powder River Basin 8400

Utah/Colorado 

Source: Derived from Bloomberg, L.P. data. 

Tons % of 

(Millions) Total

Central Appalachia 231 20.8

Southern Appalachia 22 2.0

Mid-Continent: Gulf Lignite 54 4.8

Mid-Continent: Illinois Basin 91 8.2

Mid-Continent: Interior 2 0.2

Northern Appalachia: Northeast 111 10.0

Northern Appalachia: Ohio 23 2.1

Western: Central Rockies 60 5.4

Western: Four Corners 41 3.7

Western: Northern Lignite 30 2.7

Western: Northern PRB 40 3.6

Western: Raton/Canon City 0 0

Western: Southern PRB 382 34.4

Western: Southern Wyoming 15 1.3

Western: Washington 6 0.5

Total 1,109 100.0

Source: Derived from Platts data. See source note 2. 

Note: Sum of components may not equal total due to independent rounding.

Coal Market Overview (Million Short Tons)

Production by Region 2003 2004 Consumption By Sector 2003 2004

Appalachian 376 389 Electric Power 1,005 1,015

Interior 146 146 Coke Plants 24 24

Western 549 575 Other Industrial Plants 61 61

Coal Refuse Recovery 1 1 Residential/Commercial Users 4 4

Total 1,072 1,112 Total 1,095 1,104

U.S. Coal Trade Year-End Coal Stocks

Exports 43 48 Electric Power 122 107

Imports 25 27 Other Industrial Plants 44 41

Net Exports 18 21 Total 166 147

Source: Derived from EIA data. See source note 1. Note: Sum of components may not equal total due to independent rounding.

Coal Consumption

Coal consumption grew slightly in 2004, by about 1%. The electric power sector consumed a record amount of coal in 2004 and

accounted for 92% of the total, despite the generally mild weather that moderated electric demand. Nevertheless, coal’s share of

overall net generation declined across the country. About 75% of

the national increase in coal consumption occurred in two areas—

the East North Central and Mid-Atlantic census regions.

Coal Production for 2004
Prices

Estimated average annual spot7 prices increased markedly for

coal purchased in most markets: 69% for central Appalachia,

49% for northern Appalachia, 25% for Illinois Basin and 48%

for Colorado.8 Factors accounting for higher coal prices in 2004

included:

• Structural imbalances in production and consumption.

• High gas prices.

• Higher oil costs which drove up the cost of mining and

shipping. 

• Net increased exports of bituminous coal as a consequence of

high international prices and the comparatively weak dollar.9

• Declining mining productivity.

• Ongoing production and productive capacity challenges

including reserve degradation, legacies of past lawsuits, bankruptcies, deferred investment in new mines, temporary mine

closures due to fires, permitting delays and new regulations

affecting coal hauling by truck in West Virginia and

Kentucky. 

Coal transportation and handling (T&H)10 charges added between

a quarter and a half of the total delivered cost of coal in 2004.

Estimated annual costs as a percentage of total delivered costs

changed little between 2003 and 2004 in most North American

Electric Reliability Council (NERC) regions. Average T&H costs

exceeded $14/ton and were generally higher in eastern NERC

regions: Northeast Power Coordinating Council, Florida

Reliability Regional Council, and the Mid-Atlantic Area Council.

In these areas, T&H costs climbed from 18% to 28% of total delivered coal costs. Estimated T&H costs were much lower, on average, in the Western Electric Coordinating Council region because

many of its coal-fired plants are situated in close proximity to coal

supplies.11

State of the Markets Report • June 2005 207

Coal

Electric Power Coal Consumption Across the U.S. (Millions of Tons)

U.S. Total = 1,015

New England

8.3 (1.8%)

Mid-Atlantic

67.5 (4.3%)

South Atlantic

East South 170.9 (-0.6%)

Central

109.0 (2.0%) West South

Central

152.9 (0.8%)

West North

Central

147.7 (-0.8%) Mountain

118.5 (1.6%)

Pacific

Contiguous

9.9 (-7.8%)

Source: Derived from EIA data. See source note 3.
208 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Transportation Constraints

Despite numerous constraints along the coal transportation network in 2004, total carloadings of coal increased 3%. Moreover,

Energy Information Administration (EIA) analysis of U.S. Army

Corps of Engineering data on tonnage indicators for coal and coke

suggested that waterborne coal distribution probably increased

roughly 4% to 5% in 2004. 

Coal distribution networks experienced growing pains in 2004.

On many segments, trains rolled 24 hours a day, 7 days a week.

Hence, delays on some segments had ripple effects on the distribution network, with few opportunities to accelerate deliveries

and compensate for such slowdowns. Increased eastern metallurgical coal exports, most of which were shipped from the Hampton

Roads and Baltimore terminals, strained rail deliveries of domestic coal.12 Lack of spare railroad capacity likely constrained spot

purchases of coal from the Powder River and Uinta Basins.

Eastern rail delays forced market participants to use river barges

when possible. Barge traffic, however, was impeded by lock

maintenance, flooding and sunken barges. In Kentucky, stricter

enforcement of weight limits on trucks hauling coal reduced the

size of hauls by 40% to 50% and led to delays in delivery of central

Appalachian coal.13 Union Pacific struggled to keep up with

increased demand with deliveries thwarted by a lack of equipment and insufficient personnel, in part reflecting the loss of

more senior employees than anticipated.14

Coal 

Transportation and Handling Costs

0%

10%

20%

30%

40%

50%

60%

NPCC

MAAC

FRCC

MAIN

SERC

ERCOT

MRO

SPP

ECAR

WECC

Percent of Delivered Coal Cost

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

18.0

20.0

T&H in Dollars Per Short Ton

Percentage of T&H of

Total Delivered Cost 

Tons & Handling Cost

Source: Derived from Platts CoalDat data.

Company Production Percentage of U.S. Production 

(Millions of Short Tons)

1 Peabody Coal Co. 192 17%

2 Kennecott Energy & Coal Co. 124 11%

3 Arch Coal, Inc. 115 10%

4 CONSOL Energy, Inc. 65 6%

5 Foundation Coal Corp. 60 5%

6 A.T. Massey Coal Co., Inc. 39 4%

7 Vulcan Partners, LP 36 3%

8 North American Coal Corp. 31 3%

9 Westmoreland Coal Co. 29 3%

10 TXU Corp. 24 2%

All Others 392 35%

Total 1,109 100%

Source: Derived from Platts CoalDat data. 

Note: Sum of components may not equal total due to independent rounding.

Coal Industry Concentrations
Concentration Measures

Coal industry consolidation continued in 2004. Arch Coal Inc.

(the third-ranked producer) acquired Vulcan Partners (the seventh-ranked producer). By the end of the year, the top 10 coal

producers accounted for 65% of total coal production. By comparison, in 1994 the top 10 coal producers constituted 41% of total

U.S. production.15

Coal Stocks

Total coal stockpiles declined by 18 million short tons in 2004.

Coal-fired power generators drew down their stockpiles for the

second year in a row with end-of-year stockpiles down 12%. U.S.

coal stocks reached a record low of 37.5 days of supply in July.16 PA

Consulting estimated that less than a 30-day supply of coal existed

in the Mid-Atlantic, South Atlantic, and East South Central census regions in July—all of which are central Appalachian coaldependent.17

State of the Markets Report • June 2005 209

Coal

Power Plant NERC Region Average 2004 T&H 

Cost from Western Market

ECAR $4.3

ERCOT $2.3

FRCC $12.6

MAAC $15.5

MAIN $10.3

MRO $8.5

NPCC $18.1

SERC $7.5

SPP $6.2

WECC $4.0

Source: Derived from Platts CoalDat data. 

Transportation and Handling Costs

1 “Table 8.2: World Estimated Recoverable Coal,” International

Energy Annual 2002, Energy Information Administration (EIA).

2 In the past, coal prices have been relatively stable, especially

compared with other fossil fuels. Changes currently underway

in the industry, however, may augur a period of increased price

volatility. 

3 “Coal Price Volatility Is Here to Stay,” PA Consulting, Jerry

Eyster, April 26, 2005. 

4 Exports minus imports of coal. 

5 “Coal Price Volatility Is Here to Stay.” 

6 “U.S. Coal Supply and Demand: 2004 Review,” Fred Freme, EIA,

April 2005. 

7 Based on information derived from CoalDat, Spot transactions

represented about 15% of total coal purchases in 2004; midand long-term contracts accounted for the remainder.

8 Average annual percentage price differences derived from

Bloomberg, L.P. coal price information. 

9 According to EIA, delivered coal prices in international coal markets soared because of the withdrawal of Chinese coal and

coke from markets and extreme demand for bulk carriers by a

booming Chinese steel industry.

10 Includes all forms of intermodal transportation: rail, barge, and

truck, plus any other transloading charges from one form of

transportation to another. 

11 Sometimes referred to as minemouth plants. 

12 EIA. 

13 Coal Market Report, EIA, week ending July 25. 

14 EIA. 

15 “Coal Price Volatility Is Here to Stay.” 

16 “What Does the Coal Market Do for an Encore?” Coal Age, PA

Consulting, Jerry Eyster, January 2005. 

17 According to PA Consulting, the following states had unusually

low coal inventories: Pennsylvania (15 days), South Carolina

(23 days), Tennessee (24 days), Delaware/Maryland (28 days),

North Carolina (29 days), and New Jersey (30 days).

Endnotes
210 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Coal 

Source notes

1. “U.S. Coal Supply and Demand: 2004 Review,” EIA, Fred

Freme, April 2005. 

2. Excludes waste recovery coal. 

3. “U.S. Coal Supply and Demand: 2004 Review,” Fred Freme, EIA.

April 2005. 

Disclaimer: This report contains analyses, presentations and 

conclusions that may be based on or derived from the data

sources cited, but do not necessarily reflect the positions or 

recommendations of the data providers. 
When generation outages occur, transmission is constrained or demand is high, the marginal costs of production and/or electricity prices can rise substantially, if only for

short periods of time. As a consequence, market prices rise as

well. During periods of such high prices, even a little load

reduction could reduce total purchase costs substantially.

Nevertheless, few customers have incentives to respond to

these higher prices in time to help. Better integration of the

demand side into electricity markets can improve market efficiency, help avoid the inappropriate exercise of market power,

reduce price volatility, and reduce costly transmission and generation infrastructure investment needed solely to serve load

during the limited periods of peak demand or other system

stress. In addition, demand response supports system reliability and resource adequacy. 

The term demand response is often confused with other demandside market activities. For the sake of this section, demand

response refers to the application of price and load adjustment

mechanisms to balance energy supply and demand with particular attention to cases where market clearing prices are high

because of either high marginal costs or scarcity pricing. The

U.S. Demand Response Coordinating Committee (DRCC) further defines demand response as “providing electricity customers in both retail and wholesale electricity markets with a

choice whereby they can respond to dynamic or time-based

prices or other types of incentives by reducing and/or shifting

usage, particularly during peak periods, such that these demand

modifications can address issues such as pricing, reliability,

emergency response, and infrastructure planning, operation,

and deferral.” Energy efficiency and distributed generation,

which complement demand response near the point of use, are

not included here.

Demand Response

State of the Markets Report • June 2005 211

Effects of Demand Response on Markets

Fixed 

Demand 

Clearing 

Price with 

Demand 

Response 

Clearing 

Price No 

Demand 

Response 

Quantity

Supply 

Demand 

Response Price 

• Mild summer weather limited

incentives for participation

and the need to operate

demand response programs.

Nationally, summer 2004 was

the ninth coolest on record.1

Most of this cooler than 

average weather affected

eastern states where most

wholesale demand response

programs exist. Actual peak

demand in the Northeast was

5% lower than projected for

normal weather.2 Reliabilitybased demand response programs in the eastern regional

transmission organizations

(RTOs) likewise were not 

triggered. Western states, on

the other hand, experienced

warmer than normal weather,

requiring demand reductions

in Arizona and conservation

requests in California. 

• National and regional 

coordination on demand

response increased somewhat. Efforts led to information

sharing among industry participants already in pursuit of

successful demand response

in markets and heightened

awareness of demand

response industry-wide.

Coordination efforts included

those of the DRCC, the 

Mid-Atlantic Distributed

Resources Initiative (MADRI),

and the PIER Demand

Response Research Center.3

• Innovative demand response

technologies and pricing 

programs continue to make

some progress. Technologies

that allowed an automated

reduction in demand from 

signals like high prices 

comprised the following:

advanced meters, energy

information systems,

advanced building controls,

and internet communication

systems between the system

operator and customer to

allow for real-time adjustments to energy usage.

Dynamic pricing programs

(electricity rates that vary by

time of use) were offered in

some states, including voluntary critical peak pricing in

California and default realtime pricing for large Niagara

Mohawk customers in New

York. Northeast RTOs continued to explore ways to integrate demand into wholesale

markets. PJM proposed, for

example, to allow demand to

bid in spinning reserve and

capacity markets, as well as a

financial options market for

demand-side resources.

Focal Points for 2004
212 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Demand response activity in 2004

According to the North American Electric Reliability Council

(NERC), 3% of 2004 peak load was available for demand

response.4 Because NERC’s estimates were compiled to support

reliability planning, only demand response capability with a

high certainty of operation during periods of peak demand was

included. Additional demand response capability could have

also been made available through price-based demand response

programs or voluntary pleas for customers to cut load. The

amount of demand response actually used during 2004 was not

available on an aggregate regional or national level.

The NERC numbers may include wholesale demand response

programs that vary by region and include both reliability and

price-based demand response programs. Price-based demand

response programs in northeast RTOs saved 61,373 MWh during the 2004 reporting period. Because California utilities and

regulatory entities were advancing their own demand response

programs in the state, California independent system operator

(CAISO) participation in demand response was limited to its

program. CAISO’s program allows load to participate in the

market as supplemental energy and ancillary services. During

summer 2004, CAISO had an average of 77 MW of load participation available during peak times under its program.5

Northeast RTOs published estimates for the value and costs of

demand response and associated programs in their region based

on 2004 data, as summarized below.

• ISO-NE estimates showed that the greatest market price

reduction (1%) was a result of its real-time price response

program during the winter. Total price response savings

were $4,876,349, with $1,040,206 paid by ISO-NE to market

participants.6

• NYISO data showed that each 1% of load reduced in summer 2004 in turn reduced locational-based marginal prices

by 1.2% to 2.3% in the day-ahead market and 0.6% to 1.8%

in the real-time market, depending on zone. Total NYISO

market savings during the summer equaled $45,936, with

payments of $40,651 to market participants.7

• PJM estimates showed the price effect of its economic program to be $1 per MWh, on average, based on actual

demand reductions and real-time supply curves. PJM surmised that a 1,000 MW load reduction would have led to a

$5 per MW reduction in locational marginal prices. Total

payments to market participants under the PJM demand

response program amounted to $1,671,606.8

Demand Response

2004 NERC-Reported Demand Response

Estimated Peak Demand Actual Peak Estimated Demand Response Peak Demand Reponse 

Response (MW) Demand (MW) as Share of Peak Demand Growth from 2003 (MW)

ECAR 2,643 95,300 3% -313

ERCOT 892 58,531 2% 173

FRCC 2,822 42,243 7% 27

MAAC 1,082 52,049 2% -191

MAIN 3,191 53,348 6% -18

MRO 544 34,852 2% -1,052

NPCC 2,115 98,454 2% 2,115

SERC 5,781 157,678 4% 221

SPP 990 39,893 2% -430

WECC 2,561 141,100 2% 740

TOTAL NERC 22,621 773,448 3% 1,272

Source: Derived from NERC Summer Assessments for 2003, 2004, and 2005. Note: “Estimated peak demand response” includes interruptible demand and direct-control,

demand-side management.
Price-based demand response in retail markets is designed

using a form of dynamic pricing like time-of-use rates, critical peak pricing, or real-time pricing. Dynamic pricing helps

markets operate more efficiently by creating more elastic

demand. Time-of-use rates charge a premium during periods of higher system usage with rate savings during all other

hours. Critical peak pricing includes a third, much higher,

rate during only a few hours of high load days. Retail rates

under real-time pricing change more frequently, often by the

hour. A June 2004 PJM survey identified 7,030 MW of load

in New Jersey and Maryland exposed to real-time prices

either directly or through intermediary competitive suppliers.9

In addition to dynamic pricing, retail markets also incorporate demand response through programs that allow a utility

to directly control the customer’s load, interruptible rate

schedules, and demand bidding programs. The PJM survey

found 934 MW in the PJM territory enrolled in independent

demand response programs, 203 MW in price-based programs, 453 MW under interruptible load programs, and 278

MW in emergency programs.10

State of the Markets Report • June 2005 213

Demand Response

Northeast RTO Demand Response Programs

Program Type 2004 Program Usage

Price-Based Reliability- Achieved Program Enrollment as % Regional

Based Reduction Enrollment of 2004 Peak Load Variations

ISO-NE

Real-Time Price Response Program (RTPR) Price-Taker 9,216 MWh 108 MW 0.4%

Real-Time Demand Response Program (RTDR) Emergency & 0 165 MW 0.7%

Real-Time Profiled Response Program (Profile) Contractual 0 83 MW 0.3%

NYISO

Day-Ahead Demand Response Program Bid-Based 3,535 MWh 377 MW 1.3%

(DADRP)

ICAP Special Case Resources (SCR) Contractual 0 981 MW 3.5%

Emergency Demand Response Program (EDRP) Emergency 0 581 MW 2.0%

PJM

Economic Load Response Programs (ELRP) 48,622 MWh 724 MW 0.7%

• Day-Ahead Option (ELRP-DA) Bid-Based 179 MWh

• Real-Time Option (ELRP-RT) Price-Taker 46,561 MWh

• Nonhourly, Metered Program (Pilot) Varies 1,881 MWh

Emergency Load Response Program (Emergency) Emergency 0 1,385 MW 1.3%

Active Load Management (ALM) Emergency 0 1,806 MW 1.7%

Source: Derived from ISO-NE, NYISO, and PJM reports. See source note 1.

Enrollment varies by zone. 

CT zone accounts for 89% of

RTDR and 29% of RTPR. 

NEMA makes up majority (37%) 

of RTDR and ME is majority 

(91%) of Profile program.

Enrollment varies by zone. 

NYC and Long Island (Zones J&K)

account for 53% of EDRP load,

28% ICAP-SCR, & 4% DADRP. 

Western superzone (Zones A-E) 

is 29% of EDRP, 64% of 

ICAP-SCR, & 73% of DADRP.

Economic program 

enrollment varies 

significantly by PJM Control

zones. 82% of MWh 

reductions occurred in 

single zone (AP). Two zones

had no DR activity (PEPCO

and RECO).
214 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

1 National Oceanic and Atmospheric Administration (NOAA),

“Climate of 2004-Annual Review, U.S. Summary,” National

Climatic Data Center, January 13, 2005. Data for 110 years.

NOAA defines summer as the period from June through August.

2 Based on “projected net internal demand” and “last summer’s

peak demand” for the Northeast Power Coordinating Council

and the Mid-Atlantic Area Council in 2004, as published in the

North American Electric Reliability Council 2004 Summer

Assessment and 2005 Summer Assessment.

3 DRCC is a national group of utilities, regional transmission

organizations, and governmental entities serving as the U.S.

participant in the International Energy Agency’s Demand

Response Resources Task XIII Project. MADRI has a regional

regulatory focus and includes utility commissioners from the

mid-Atlantic states, along with representatives from PJM, DOE,

EPA and industry stakeholders, similar to the New England

Demand Response Initiative that concluded in 2003.

4 2005 Summer Assessment: Reliability of Bulk Electricity Supply

in North America, North American Electric Reliability Council,

May 2005.

5 2005 Summer Operations Assessment, California Independent

System Operator, March 23, 2005, 11.

6 ISO-NE estimates from the Independent Assessment of Demand

Response Programs of ISO New England, Inc., FERC Docket No.

ER02-2330-033, filed on December 30, 2004. Savings included

$222,745 from the change in price for load cleared in real time

and $4,653,603 saved from the corresponding reduction in

monthly average real-time prices to bilaterally contracted load.

7 Estimates from New York Independent System Operator, Inc

Seventh Bi-Annual Compliance Report on Demand Response

Programs and the Addition of New Generation in Docket. No.

ER01-3001-00, e-filed December 1, 2004. Load-serving entities

saved $8,996 in purchases from the NYISO and bilateral contract supply costs were reduced by $36,940 as a result of lower

day-ahead prices.

8 Estimates from 2004 State of the Market by the PJM Market

Monitoring Unit, published March 8, 2005. The 1,000 MW load

reduction estimate assumes real-time supply curves for a representative day during summer 2004.

9 PJM survey results, as reported in PJM’s 2004 State of the

Market by the PJM Market Monitoring Unit, published March 8,

2005.

10 Ibid.

Demand Response

1. Derived from Independent Assessment of Demand Response

Programs in ISO New England Inc., FERC Docket No. ER02-2330-

033 filed December 30, 2004; New York Independent System

Operator, Inc. Seventh Bi-Annual Compliance Report on

Demand Response Programs and the Addition of New

Generation in Docket No. ER01-3001-00, e-filed December 1,

2004; and 2004 State of the Market by the PJM Market

Monitoring Unit dated March 8, 2005. ISO-NE and NYISO reductions and enrollment are for the period September 2003 to

August 2004. In NYISO, 11 MW of unsold ICAP is included in the

EDRP total. PJM reductions and enrollment are for the period

January to September 2004 Emergency. In PJM, 317 MW of ALM

resources are also included in the Emergency Load-Response

Program.

Disclaimer: This Report contains analyses, presentations, and 

conclusions that may be based on or derived from the data sources

cited, but do not necessarily reflect the positions or recommendations

of the data providers. 

Source notes

Endnotes
Market-based emission allowance trading helps generators

choose their most cost-effective form of compliance with

environmental regulations. Such trading also provides incentives

for technology development and affects electricity and fuel markets in several ways. They have a bearing on infrastructure investments, fuel supply decisions, generator bidding behavior, and

financial energy trading. The following pages address federal programs, although emission allowance markets also exist at the state

level. Apart from environmental regulations surrounding emission allowance trading, power generators must meet other market and nonmarket-based environmental regulations exist at both

the federal and state level.

Since 1994 and 1998, respectively, sulfur dioxide (SO2) and nitrogen oxides (NOx) have been traded as emission allowances under

the two federal “cap-and-trade” programs, the Title IV Acid Rain

Program and the NOx Budget Program. Under these federal policies, power generators received initial emission allowances based

on total heat input as a measure of their efficiency.1 All current

and future-year allowances were granted at the start of the program, creating emission allowance accounts and an opportunity

for trading all future-year vintage allowances. Generators use

allowances of current or earlier vintage years to meet annual limits.

Federal cap-and-trade programs are not limited to power generators, although generators contribute 67% of SO2 emissions and

22% of NOx emissions.2 In 2003, more than 90% of these two

power plant emissions came from coal-fired power units,3 only

22% (83 GW) of which had installed scrubber equipment to

reduce emissions.4 The map shows the location of fossil-fuel-fired

plants in the United States, along with the region boundary for

the NOx State Implementation Plan (SIP) Call markets. The NOx

SIP Call requires states that contribute significantly to pollution

problems in other states to reduce their NOx emissions during the

ozone (summer) season. 

Emission Allowances

State of the Markets Report • June 2005 215

1,500 to 3,700

800 to 1,500

300 to 800

0 to 300

Coal-fired generators Gas- and oil-fired generators

NOx SIP Call May 2007

NOx SIP Call May 2003

NOx SIP Call May 2004

Fossil Fuel Power Generators in the NOx and SO2

Allowance Market

• Increased SO2 prices. During

2004, daily SO2 spot market

index prices peaked at $722

per ton on November 29,

2004.5 Prices began to rise in

July, then declined throughout

August, only to rise again in the

fall. Average SO2 prices in the 

second half of 2004 were

approximately double the 

average price during the first

half of the year. SO2 prices

increased due to several factors

in the SO2 and related markets,

including (1) declining volume

in the SO2 bank as the market

matured, (2) increasing spread

between high- and low-sulfur

eastern coal prices, (3) high oil

and gas prices favoring

increased coal use by power

generators, and (4) uncertainty

regarding pending regulations.6

• NOx SIP Call Expansion.

Starting May 31, 2004, areas 

in 11 additional states came

under the NOx Budget Program.

Power generators in these

areas were granted NOx

allowances, increasing the footprint of the NOx market. The

expanded region contributed to

increased market liquidity as

additional market participants

became eligible to trade.

During 2004, NOx allowance

transfer volumes were 26 

percent higher than during the

previous peak and nearly 

double the transfer volumes of

the previous year. The 2004

vintage allowance prices

remained lower than prices for

2003 vintages, in part because

of expected surpluses in supply

during the shortened compliance period.7

• Diverse trading entities. During

2004, emission allowances

were transferred among pure

emission traders—parties that

do not themselves emit 

pollutants. As discussed in 

the market concentration 

section, brokers and financial

players were active in the 

emission market during 2004.

These parties may be holding

allowances in their accounts

only for limited periods of time,

perhaps for clearing purposes,

or under swap arrangements

where allowances are transferred back to emitting entities

prior to annual reconciliation. 

Focal Points for 2004

Source: Derived from Platts data. See source note 1. 

Note: Not all counties in highlighted states are included in the NOx SIP Call.
Spot Market Prices

$0

$1,000

$2,000

$3,000

$4,000

$5,000

1/1/04 3/1/04 5/1/04 7/1/04 9/1/04 11/1/04

 Index $/ton

$0

$200

$400

$600

$800

Index $/ton

NO SIP Call Allowances 2004 MPI

SPOT SO Market MPI 2

X

Source: Derived from Cantor Fitzgerald market price indices.

$1,500

$2,000

$2,500

$3,000

$3,500

$4,000

$4,500

1/1/04 3/1/04 5/1/04 7/1/04 9/1/04 11/1/04

NOx Market Price Indices by Allowance Year ($/ton)

NO SIP Call Allowances 2005 MPI

NO SIP Call Allowances 2006 MPI

NO SIP Call Allowances 2007 MPI

NO SIP Call Allowances 2008 MPI

NO SIP Call Allowances 2004 MPI

X

X

X

X

X

Source: Derived from Cantor Fitzgerald market price indices. 

216 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

For SO2, EPA holds an annual auction of allowances at the end of

March. The 2004 auction cleared at $260 per ton—$10 per ton

below the cash prices for the two weeks prior to the auction and

$88.20 per ton above the previous year’s auction prices.8 Since the

March auction, SO2 spot market prices have more than doubled,

whereas NOx spot prices remained more level.

Although 2004 vintage allowances accounted for most 2004

trades, allowances for other vintage years were also traded. The

traded value of future vintage NOx allowances during 2004 was

highest for the next-year vintage allowances and then dropped for

all future years. Similar declining value of future vintage

allowances occurred in the SO2 market, partly in anticipation of

new emission-reducing scrubber installations. 

On December 10, 2004, the Chicago Climate Futures Exchange

launched trading of SO2 allowance futures contracts, called the

Sulfur Financial Instrument (SFI). The contract is designed to

facilitate price hedging for SO2 allowances eligible for delivery on

EPA’s Allowance Tracking System (ATS). Nine contracts were

available: quarterly contracts for the next six quarters and annual

contracts for the next three years. On December 10, 2004, the

March 2005 and June 2005 SFI contracts settled at $712 and $715, 

respectively.9

Emission Allowances

SPOT AND FUTURES PRICES

0

100

200

300

400

500

600

700

800

Volume (000s tons)

0

100

200

300

400

500

600

700

800

Count

Trading Volume Transfer Volume

No. of Trades No. of Transfers

Trading Volume 323 392 390 250

Transfer Volume 531 410 414 753

No. of Trades 97 129 128 80

No. of Transfers 300 266 392 714

Q1 2004 Q2 2004 Q3 2004 Q4 2004

Source: Derived from EPA and Cantor Fitzgerald data. See source note 2. 

0

50

100

150

200

250

300

350

Volume (000s tons)

0

500

1,000

1,500

2,000

2,500

3,000

3,500

Count

Trading Volume Transfer Volume

No. of Trades No. of Transfers

Trading Volume 5 12 14 8

Transfer Volume 13 34 55 317

No. of Trades 57 98 139 84

No. of Transfers 199 491 718 3,263

Q1 2004 Q2 2004 Q3 2004 Q4 2004

Source: Derived from EPA and Cantor Fitzgerald data. See source note 2. 

ALLOWANCE TRANSFERS AND TRADING VOLUMES

Future Year Vintage NOx Allowance Prices

SO2 2004 Vintage Transfers and Trading NOx 2004 Vintage Transfers and Trading
State of the Markets Report • June 2005 217

Emission Allowances

0

5

10

15

20

25

30

1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

Volume (million tons)

0

5000

10000

15000

20000

25000

30000

35000

40000

No. of Transfers

Bank (million tons)

Transfer Volume (million tons)

No. of Transfers

Source: Derived from EPA data. See source note 3.

NOx Private Transfer History

0

100

200

300

400

500

600

700

1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004

Volume (million tons)

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

No. of Transfers

Transfer Volume (000s tons)

No. of Transfers

Source: Derived from EPA data. See source note 3.

Emission allowances can be acquired in several ways. They can be

purchased directly from a company or an individual that holds

them, through EPA’s annual auction at the end of March (SO2

only), or through a broker. Entities trade allowances according to

individually agreed-upon terms. Some of these trades are surveyed by brokers and trade publications. Others are conducted

under bilateral deals not transparent to the market. Before an

allowance can be used to meet annual environmental compliance

requirements, its transfer must be reported to EPA’s Allowance

Tracking System databases (i.e., ATS for SO2 and NATS for NOx). 

The graphs show the volume and number of allowance transfers,

as reported to EPA, along with trades surveyed by Cantor

Fitzgerald, a leading broker, for 2004 vintage NOx and SO2

allowances. During 2004, the reported SO2 transfer volume

totaled 2.1 million tons, averaging 1,260 tons per transfer.

Transfers of NOx allowances reported to EPA equaled 418,108

tons, averaging 90 tons per transfer. Broker-surveyed trading

totaled 1.4 million tons SO2 and 39,000 tons NOx.

In addition to 2004 vintage allowances, generators used pre-2004

vintage allowances to meet 2004 compliance standards. Pre-2004

vintage allowances accounted for 74% of the total SO2 transfer

volume in the EPA database, whereas 2004 vintage allowances

accounted for only 14%, probably because of the ability to bank

allowances in the SO2 market. Since the start of Phase II in the

year 2000, the SO2 bank has been declining, supporting the high

transfer activity of pre-2004 vintage allowances. NOx allowance

markets are less favorable for banking.10 Only 4% of NOx

allowances transferred in 2004 were for pre-2004 vintages

allowances, whereas 68% were for current-year (2004) vintage

allowances. 

Higher emission allowance prices do not directly translate

into higher electricity prices. Not all power generators need

to purchase SO2 allowances on the spot market to meet environmental compliance standards. Some generators are able to

use their own allowances. In most regions, coal-fired units

run as baseload units and do not tend to set marginal power

prices, especially on-peak. Still, if a coal-fired unit in the

Midwest, for example, needed to use SO2 allowances and

credited them to their marginal cost of generation, the SO2

spot prices during 2004 could have added $0.80 to $17.40 per

MWh to the price of electricity, subject to the type of coal

burned. NOx prices could have added $1.60 to $4.00 per MWh

during 2004.11 Generators consider the combined cost of coal

and emissions when making their fuel supply decisions,

because the lower-priced coal supply has higher sulfur 

content.

Emission Prices and Electricity Prices

SO2 Private Transfer History
218 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Emission Allowances

During 2004, transfers of all vintage SO2 emission allowances

totaled 15.2 million tons compared with 0.6 million tons of NOx

allowances. The top 10 companies accounted for 36% of total SO2

transfer volume. Morgan Stanley Capital Group, a financial services company, accounted for the most SO2 allowance transfers by a

single company (8%). 

Market shares of transfer volumes for NOx allowances were distributed more evenly. The top 10 transfer companies accounted

for only 21% of the total volume. No one company contributed

more than 4% of total NOx transfer volume. In both the SO2 and

NOx markets, electric utilities and their unregulated affiliates

made up nearly 80% of transfer volumes by the top 10 companies. 

In 2004, the top brokers for emission allowance trading were

Cantor Fitzgerald, Amerex, Evolution Markets, and NatSource.

These brokers facilitated trading between two parties and also

took title to both SO2 and NOx allowances as recorded on EPA’s

Allowance Tracking System.

MARKET CONCENTRATION 

Total Rank as Rank as Name Total Amount as Amount as 

Rank Transferor Transferee Amount (tons) Transferor (tons) Transferee (tons)

1 1 1 Morgan Stanley Capital Group 2,287,995 1,255,006 1,032,989

2 2 2 Ohio Power Company 1,696,668 915,729 780,939

3 9 3 CG&E General Account 1,086,178 397,508 688,670

4 4 5 Millennium Environmental Group 989,696 494,848 494,848

5 5 6 Kansas City Power & Light Co. 920,283 452,373 467,910

6 3 9 PSEG Energy Resources & Trade LLC 874,029 535,924 338,105

7 7 7 Dominion Energy Marketing, Inc 828,760 414,380 414,380

8 15 4 PSI General Account 818,177 249,185 568,992

9 8 8 APS 809,046 408,637 400,409

10 6 12 Constellation Energy Commodities Grp Inc 685,473 425,591 259,882

Source: Derived from EPA data. See source note 2.

Total Rank as Rank as Name Total Amount as Amount as 

Rank Transferor Transferee Amount (tons) Transferor (tons) Transferee (tons)

1 3 1 Constellation Energy Commodities Group Inc 41,423 15,889 25,534

2 1 3 DTE Coal Services 33,381 16,543 16,838

3 4 4 PPL Generation LLC 30,831 15,571 15,260

4 2 7 Mirant Americas Energy Marketing LP 28,662 16,500 12,162

5 26 2 CG&E General NOx Account 25,275 6,753 18,522

6 29 5 Columbus Southern Power Company 20,944 6,143 14,801

7 9 8 Cantor Fitzgerald Brokerage 20,020 9,264 10,756

8 10 10 Cumberland 19,771 9,263 10,508

9 22 9 Orion MidWest 17,563 6,955 10,608

10 6 19 PPL Rights 17,458 10,479 6,979

Source: Derived from EPA data. See source note 2.

Top 10 Companies - NOx Transfers

Top 10 Companies - SO2 Transfers
State of the Markets Report • June 2005 219

Emission Allowances

SO2 Amounts (tons) NOx Amounts (tons)

Broker As Transferor As Transferee Total As Transferor As Transferee Total

Amerex USA 52 52 104 3,781 3,781 7,562

Cantor Fitzgerald Brokerage 154,759 125,071 279,830 9,264 10,756 20,020

Evolution Markets LLC 7,600 55,612 63,212 1,621 2,001 3,622

Natsource 106 125 231 0 0 0

Source: Derived from EPA data. See source note 2. 

Emission Allowance Transfers by Brokers

1 The number of allowances granted to a generator varies by

state, although most states base allocations on heat input.

2 U.S. Environmental Protection Agency, EPA Acid Rain Program

2003 Progress Report, Clean Air Markets Division, Office of Air

and Radiation: EPA 430-R-04-009, September 2004.

3 From Platts CoalDat emission data for 2003 and EPA’s preliminary 2003 national emission totals.

4 From Platts CoalDat plant data in the February 2005 data set.

5 As reported by Cantor Fitzgerald. 

6 In 2005, Clear Skies and/or the Clean Air Interstate Rule may

significantly reduce the amount of allowable SO2 emissions in

the future.

7 The 2004 compliance period began on May 31, not May 1, as in

2003.

8 Auction results are from EPA’s Clear Air Markets website. For

cash prices, see the Chicago Climate Futures Exchange Sulfur

Dioxide Market Report, Vol. 2, No. 3, February 16–March 15,

2005.

9 For price information, see the Chicago Climate Futures

Exchange Sulfur Dioxide Market Report, Vol. 2, No. 1, December

10, 2004–January 14, 2005.

10 The use of banked NOx allowances above a certain threshold

will require the generator to surrender two allowances for each

ton of NOx emissions.

11 The cost estimate assumes a coal-fired power plant heat rate of

10,500 Btu/kWh, coal spot prices from Bloomberg, coal transportation cost derived from CoalDat, and SO2 spot and 2004

NOx market price indices from Cantor Fitzgerald. Heat content

and rates of emission vary, depending on the source of coal,

whether from Central Appalachia, northern Illinois, or the

Powder River Basin. NOx prices apply during the summer compliance period, May 31 to September 30, 2004, only. 

Endnotes
220 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Emission Allowances

1. Capacity based on RDI Modeled Capacity data from January

2004 to November 2004. NOx SIP Call states based on EPA’s

2003 Progress and Compliance Report of the NOx Budget

Trading Program.

2. All private transfers confirmed and trades surveyed from

1/1/2004 to 12/31/2004.

3. EPA's ATS and NATS private transfers through December 31,

2004 and banked allowances as reported in EPA Acid Rain

Program Progress Reports 2000-2003. Number of transfers

counts the transfer of different allowance years within the same

transaction separately. Banked SO2 allowance volumes are as

of reconciliation on March 1 of each year.

Disclaimer: This Report contains analyses, presentations and 

conclusions that may be based on or derived from the data sources

cited, but do not necessarily reflect the positions or recommendations

of the data providers. 

Source notes
I

n 2004, debt and equity market performance in the energy

sector reflected stabilizing operating performances and a

growing perception of general—not necessarily pervasive—

improvement in prospects. Two key debt and equity trends in

2004 were the stabilization of credit ratings, as companies took

steps either to reduce debt or risk, and rising stock prices, price

to earnings ratios, and dividends.

Credit Trends

The energy sector’s credit situation stabilized in 2004. For the

broad electric and natural gas sectors, the number of company

credit rating actions declined, bucking the trend established in

2001. Also, the ratio of downgrades to upgrades was significantly

lower. 

The overall sector held an average BBB rating in 2003 and 2004,

reflecting deterioration from the average A rating held in 2001. 

Strategies to improve credit ratings in 2004 were different for regulated and unregulated entities. Regulated utilities without large

affiliated merchant activities were able to improve their financial

profiles through a combination of paying down debt, scaling back

investments in unregulated activities, and exiting non-core lines

of business. By comparison, merchant generators and utilities

with significant unregulated activities had to defer or restructure

debt, sell performing assets and contracts, and raise additional

equity and convertible securities. In general, the more regulated

the business mix of the energy company, the greater the success in

stabilizing cash flows and improving the view of the debt markets

and the credit rating agencies. 

The sector was aided in its recovery by relatively benign conditions in the credit markets, affording companies that were taking

action to improve credit fundamentals and lower leverage

increased access to credit at lower costs. The cost of debt capital,

particularly for noninvestment-grade energy companies,

declined, allowing companies to borrow in the bond markets at

absolute and relative rates that were close to historic lows.

Energy companies with noninvestment-grade ratings and significant exposure to unregulated activities were generally pre0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

55%

AA A BBB BB B CCC and

lower

Beginning of 2001 Beginning of 2002

Beginning of 2003 Beginning of 2004

Beginning of 2005 5-Apr

Below Investment Grade/Speculative

(Junk)

End of 2000End of 2001End of 2002End of 2003End of 2004

2005 YTD .

Energy Debt and Equity

State of the Markets Report • June 2005 221

Standard & Poor’s Gas and Electric Ratings Actions

0

20

40

60

80

100

120

140

160

180

200

2000 2001 2002 2003 2004

Number of Ratings Actions

Ratings Upgrades

Ratings Downgrades

S&P’s Gas and Electric Ratings Distributions

Source: Derived from S&P Ratings Direct data and applied to the Energy Market

Particpant Index (EMPI). Data through 12/31/04.

2

4

6

8

10

12

14

16

18

20

12/31/00 4/30/01 8/31/01 12/31/01 4/30/02 8/31/02 12/31/02 4/30/03 8/31/03 12/31/03 4/30/04 8/31/04 12/31/04

Effective yield (%)

US Corporates, Gas&Electric

Utilities

US High Yield, Utilities

10-yr U.S. Treasury Bond

Source: Derived from Merrill Lynch data.

Source: Derived from S&P Ratings Direct data and applied to the EMPI. Data through

12/31/04.

Utilities and Merchants
222 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

sented with the greatest reduction in cost of capital and improvement in access to capital. Standard & Poor’s recently estimated

that $30 billion of debt incurred by ten troubled energy companies has been successfully deferred since December 2003.1 Though

merchants continued to successfully defer repayment of principal

by restructuring debt and extending maturities, they have not significantly reduced absolute levels of leverage. 

Equity Trends

Most significant equity market valuation metrics of energy market participants, including stock prices, price to earnings ratios,

and dividends, all improved in 2004. The market rewarded energy companies both for perception of future returns in the sector

and the attractiveness of current earnings.2 

Stock Prices 

Most energy sector stocks outperformed the stock market on average, as measured by the Standard & Poor’s 500 Index in 2004. The

energy sector’s equity market capitalization increased by $221 billion in 2004 to $1,114 billion. Even without considering the

increase in equity values for producers (which dwarf increases for

other energy subsectors), equity market capitalization increased

$89 billion in 2004 to $476 billion, slightly surpassing the $84 billion increase in 2003, and recouping more than the $97 billion of

equity losses experienced in 2002. 

There was wide divergence in the equity performance of subsectors of the energy market. Electric generators, including AES,

Calpine, and Reliant Resources, had the largest percentage

increase in equity values in 2004. Much of this market optimism

and outperformance was based on the ability of the generators to

access debt markets, refinance existing debt at more attractive

rates, and defer debt maturities. 

Producers, including super-majors like Exxon-Mobil and

Chevron-Texaco as well as smaller producers such as Apache, saw

the second greatest increase in stock prices. Midstream gas companies, including companies like El Paso Corp, Enbridge, Kinder

Morgan, National Fuel Gas Co, Questar Corp, TransCanada Corp,

and Williams Companies Inc, saw a 27% increase in stock prices.

El Paso and Williams, like generators, increased from low initial

share prices and benefited from more attractive debt market conditions as they unwound exposure to electric market positions

(namely, tolling arrangements and generation ownership).

Other midstream gas companies, such as Enbridge and Kinder

Morgan, benefited from consistent year-on-year returns, as well

as attractive dividend yields in the low-interest rate environment.

Utility parents with significant wholesale operations saw stock

prices rise 26%, also outperforming the S&P index. Reasons for

stock price gains differed among the 20 holding companies

tracked in the Energy Market Participant Index (EMPI) (including companies like Allegheny Energy, Aquila, Constellation,

Duke Energy, Exelon, First Energy, PG&E Corp, Pinnacle West,

and Public Service Enterprise Group). These companies varied in

region, scope, and scale of regulated operations as well as range of

unregulated activities. Interestingly, equity markets were not

consistent in rewarding revenue and earnings growth from

wholesale operations based on perceptions of different abilities to

repeat results and risk levels adopted to earn returns in trading

Energy Debt and Equity

Stock Prices Compared with S&P Index

-10%

-5%

0%

5%

10%

15%

20%

25%

30%

Jan-2004

Feb-2004

Mar-2004

Apr-2004

May-2004

Jun-2004

Jul-2004

Aug-2004Sep-2004

Oct-2004

Nov-2004

Dec-2004

Percent Change in Stock Price

FERC EMPI

S&P Index

Source: Derived from Bloomberg L.P. data applied to subsector components of the

FERC Energy Market Participant Index (EMPI), excluding Producers. 

Increase from

Subsector Jan-Dec 2004

Electric Generators 44%

Producers 30%

Midstream Gas 27%

Utility Parent - Sig Wholesale 26%

Gas Distributors 23%

Integrated Electric 10%

Electric Distributors 7%

Utility Parent – Min Wholesale 7%

S&P Index 9%

Source: Derived from Bloomberg L.P. data applied to sector components of the FERC

Energy Market Participant Index (EMPI). Prices averaged per group of companies.

Changes in Stock Prices
operations. In some cases, a company’s ability to exhibit effective

management of wholesale exposure aided in market outlook and

improved share performance. In other cases, companies wound

down wholesale exposure to avoid discounted earnings and

blunted rewards for this growth. Finally, some decided to maintain wholesale trading operations in the face of lower equity valuations.3

Gas distributors, 24 of which are tracked in the EMPI, delivered

stock price increases of 23%, generally because of a combination

of constant dividends, solid revenue growth, and insulation from

commodity price exposure.

Integrated electrics (20 companies), utility parents with minimal

wholesale operations (10 companies), and electric distributors (9

companies) either matched the S&P 500’s performance or narrowly underperformed it. These subsectors had performed well in

2003, and their performance can be considered in the context of

their relative initial valuations.

Price to Earnings Ratios

Last year, the median price to earnings (PE) ratio increased for the

energy sector from 14.8x in 2003 to 15.7x.4 During 2004, PE ratios

for all subsectors were above historic average levels of 12x to 13x.

For midstream gas companies, increases in earnings outpaced

increased stock prices resulting in a slight decline in PE ratios. 

However, all other subsectors experienced increases. Electric generators enjoyed the highest PE ratios of any energy subsector, at

23.6x, and also expanded their PE ratios most on an absolute basis.

As discussed earlier, the ability to access the debt markets and

extend debt maturities played a large roll in allaying concerns

among equity investors in the viability of the merchant generation companies. 

Dividends

Much of the increase in PE ratios, and therefore a significant component of the stock price appreciation in 2004 garnered by the sector, was explained by industry analysts as a function of increasing

dividends paid by the sector. After-tax dividend yields increased

because of the federal tax cut on dividends, and utility dividends

compared favorably to bond yields and alternative investments,

thereby attracting increased investment in the sector. 

This was the case despite the fact that for the sector as a whole dividend growth did not keep pace with the increase in stock prices.

Dividend yields declined slightly for the sector as a whole in 2004,

from 3.7% to 3.2%. Of the subsectors, integrated electrics and

electric distributors had the highest dividend yields, whereas midstream gas companies had the lowest yields of the dividend payers. Electric generators continued to pay no dividends. 

Examining the relationship between trailing PE ratio to dividend

payout shows that most energy companies follow a trend, with

higher payouts associated with higher valuations. Put another

way, PE ratios are higher for utility companies that pay out a higher portion of their earnings in the form of dividends to their

shareholders and reinvest a smaller portion in their businesses. 

Electric distributors that typically pay out nearly 100% of their

State of the Markets Report • June 2005 223

Energy Debt and Equity

2004 Year-End Price to Earnings Ratios

0

5

10

15

20

25

Electric

Generators

Electric

Distributors

Utility - Min

Wholesale

Integrated

Electric

Gas

Distributors

Midstream

Gas

Utility - Sig

Wholesale

Energy

Sector

Median PE Ratios

2003

2004

Source: Derived from S&P Research Insight data.

Subsector 2003 2004

Electric Generators 0.0% 0.0%

Midstream Gas 2.2% 2.8%

Utility Parent - Sig Wholesale 3.2% 3.3%

Gas Distributors 4.1% 3.3%

Utility Parent - Min Wholesale 4.3% 3.9%

Electric Distributors 4.3% 4.1%

Energy Sector 3.7% 3.2%

Source: Derived from S&P Research Insight data.

Average Dividend Yields
224 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

earnings in the form of dividends to their equity holders had

the highest PE ratios of any dividend payers. Generally, those

with the lowest dividend payouts, midstream gas, gas distributors, and utilities with significant wholesale operations, had

the lowest PE ratios. Merchant generators were the exception to this trend as they are not dividend payers. Like

“growth” stock companies past and present, they have a higher PE ratio than peers in other sub-sectors. 

Energy Debt and Equity

1 Standard & Poor’s “High Yield Energy Merchants: A Year in the

Worst Case Scenario” presented at Shared National Credit

Symposium, April 12, 2005.

2 PE ratios show what investors are willing to pay for future earnings; dividend yields show requirements for return of capital.

3 For example, Sempra and Constellation had relatively low valuations, more consistent with those of investment banks, as compared with higher valuations of Exelon and Pinnacle West, both

of which have significant wholesale operations that were not

perceived to be as focused on trading. 

4 The PE ratio, a widely used equity valuation measure, is calculated by dividing the stock price by annual earnings - PE ratio =

Price/Earnings. In 2004, the median energy sector stock price

was 15.7 times the median 2004 annual earnings (i.e. PE ratio =

15.7x).

Disclaimer: This report contains analyses, presentations, and 

conclusions that may be based on or derived from the data sources

cited, but do not necessarily reflect the positions or recommendations

of the data providers. 

Endnotes

PE Ratios vs. Dividends

0

5

10

15

20

25

30

0% 20% 40% 60% 80% 100% 120% 140% 160%

Median PE Ratios

Sector Medians

Companies in the EMPI

Util- Sig 

Wholesale

Elec Gen

Mid Stream Gas

Gas Distr

Util- Min 

Wholesale

Integ Elec

Elec Distr

Source: Derived from S&P Research Insight data.
The United States is the world’s largest consumer of petroleum

products, accounting for 21 million barrels per day (MMbd)

or a quarter of world oil consumption. The United States depends

heavily on oil imports, importing about 57% of its needs in 2004.

The United States competes in a global marketplace for oil products, and demand from developing countries is growing rapidly.

Domestic crude oil production in 2004 declined 5%. 

Oil-fired generation consumed just 3% of U.S. petroleum requirements. In the power sector, petroleum products (jet kerosene, distillate, and residual fuel oil) compete directly with natural gas,

especially in New England and some Gulf Coast states. Except

during price spikes, distillate oil has tended to set the ceiling and

residual fuel oil the floor prices of similarly located natural gas.

Oil-fired plants provide regional fuel diversity. They foster electric

power reliability when severe weather strains the natural gas system, and they can lower overall fuel costs.

Oil

State of the Markets Report • June 2005 225

Production 2003 2004 Consumption 2003 2004

OECD OECD

United States 9 9 United States 20 21

Other OECD 14 14 Other OECD 29 29

Total OECD 23 23 Total OECD 49 50

Non-OECD Non-OECD

OPEC 31 33 China 6 7

Former USSR 10 11 Former USSR 4 4

Other Non-OECD 15 16 Other Non-OECD 21 22

Total Non-OECD 56 60 Total Non-OECD 31 33

Total World Supply 79 83 Total World Demand 80 83

Source: Derived from EIA data. Includes production of crude oil (with leese condensated, natural gas plant liquids, other hydrogen and hydrocarbons for refinery feedstocks,

refinery processing gain, alchohol and liquids processed from coal and other source.

2004 2003 5-year average

WTI 7.16 5.36 5.35

NY No. 2 Fuel Oil 8.05 6.11 6.10

NY Residual Fuel Oil 5.28 5.13 4.51

Gulf Coast Residual Fuel Oil 4.24 4.42 3.93

Source: Derived from Bloomberg, L.P. data.

Oil Spot Prices ($/MMBtu)

• Increased spot prices.

Tightness in the balance 

of global production and 

consumption spurred a 33%

increase in the West Texas

Intermediate (WTI) crude oil

price. The average rose from

$31.06/bbl to $41.51/bbl in

2004.

• Hurricane-related production

shut-ins. Hurricane Ivan

immobilized production of 38

million barrels of oil from the

Gulf of Mexico or an estimated

6% of average annual 

production.1 On September

16, the day after Hurricane

Ivan made landfall, the shutin amounted to 1.4 MMbd, 

or 83% of Gulf of Mexico oil 

production.2

• Growth in global oil 

consumption. With a 16%

increase in oil use by the

Chinese, world consumption

grew 2.71 MMbd, the fastest

rate since 1976 (3.29 MMbd).

Chinese oil use accounted 

for 32% of the increase in

global consumption.3 

• Less supply flexibility. The

Organization of Petroleum

Exporting Countries’ (OPEC’s)4

spare production capacity5

dipped to 0.35 MMbd in

2004. U.S. refining capacity

averaged 93% on 

an annual basis. U.S. crude

oil stocks hovered near the

bottom of the 5-year range. 

Focal Points for 2004

World Oil Balance (MMbd)
226 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Oil

SPOT PRICES 

Spot Petroleum Product Prices 

0.00

2.00

4.00

6.00

8.00

10.00

12.00

1/5 2/18 3/31 5/13 6/28 8/10 9/22 11/3 12/17

$ MMBtu

WTI NY Distilliate

NY Residual Gulf Coast Residual

Source: Derived from Bloomberg, L.P. data. 

Non-commercial Net Open Interest 

-40,000

-20,000

0

20,000

40,000

60,000

80,000

100,000

1/6 2/8 3/12 4/14 5/17 6/19 7/22 8/24 9/26 10/29 12/1

Non-Commercial Net Open Interest Contracts

Source: Derived from CFTC's Commitment of Traders Report.

Real vs. Nominal WTI Prices 

0

10

20

30

40

50

60

5/835/845/855/865/875/885/895/905/915/925/935/945/955/965/975/985/995/005/015/025/035/04

$/Bbl

Nominal Real

During October 2004 NYMEX 

WTI price reaches $56.37

January 17, 1991 Operation Desert Storm 

begins 3:00 p.m Baghdad time.

Prices slowly recovering from 

early 1980's supply shocks

Source: Derived from Bloomberg, L.P. and Bureau of Labor Statistics data.

WTI Futures Curves

4

5

6

7

8

1/1/04 5/1/04 9/1/04 1/1/05 5/1/05 9/1/05 1/1/06 5/1/06 9/1/06 1/1/07 5/1/07

$/MMBtu

December 15, 2003 March 15, 2004 June 15, 2004

September 15, 2004 December 15, 2004

Source: Derived from Bloomberg, L.P. data.

Petroleum price trends varied by product in 2004. Average annual WTI prices increased 33% due to tightness in the global supplydemand balance. Distillate prices increased 34%. Residual oil

prices rose 4% in New York but declined 3% in the Gulf Coast. Oil

prices increased most significantly beginning in August as a result

of hurricane activity and declining inventories. 

In real dollars, WTI price increases resulted in the highest oil

prices since the Gulf War and the oil price shocks of the mid-1980s

and the late 1970s. Prices for the WTI near-month futures contract for November 2004 delivery reached a record $56.37/bbl on

October 26.

Worsening market fundamentals during the year, coupled with

anxiety about the adequacy of supplies, contributed to escalating

price expectations in crude oil futures markets. Anticipated WTI

prices for 2005 increased nearly $2/MMBtu during 2004. 

Market participants bought oil futures contracts at a record pace.

The number of light, sweet crude oil futures contracts traded

increased 16% from 45 to 53 million in 2004. More than 212,000

contracts were traded on a daily average basis. Net open interest

by noncommercial market participants averaged 38 million 

contracts. 
Consumption

Developing economies in Asia, economic recovery in the United

States, and fears of OPEC supply cuts contributed to rising oil

prices. World oil consumption rose by 2.7 MMbd to 82.5 MMbd,

a 3.4% increase from 2003. Much of that increase, 1.2 MMbd,

occurred in Asia. Chinese consumption grew by 0.86 MMbd

(16%), the lion’s share of the increase in Asian demand, while

consumption in India grew by 0.12 MMbd, or 5%.6 Korean and

Japanese oil consumption declined modestly. IEA reported that

retail oil price subsidies by some developing countries in Asia suppressed prices and artificially stimulated consumption. 

Higher fuel oil prices in the United States materially affected the

use of petroleum products used for power generation. Net generation across all sectors using petroleum liquids declined 3.6% in

2004.7

Electric utilities accounted for 62% and independent power

producers for 34% of total net generation fueled by petroleum

products. Independent power producers led the reduction, dropping 6% or 3.8 million barrels. Regional results differed, with

New York’s independent power producers increasing consumption by 22% or 3.5 million barrels because residual fuel oil was on

the margin much of the year. Similarly, Mississippi electric utilities increased petroleum consumption by 74% or nearly 2 million

barrels.8 

Stocks

U.S. crude oil stocks trended near the bottom of the 5-year average inventory range during much of 2004. Concerns about the

disposition of U.S. inventories contributed to higher WTI prices

in 2004. Distillate stocks averaged within the 5-year average band

for most of 2004. During November, distillate stock levels dipped

below the 5-year range temporarily.

Production and Refining Capacity

Net worldwide oil production increased 3.5 MMbd in 2004. The

Middle East accounted for 68% of the increase in production.

Production was affected by, among other things, political instability and strikes in Venezuela; the destruction of energy infrastructure in Iraq; Nigerian labor strikes; and disputes between the

Russian government and national oil giant Yukos. In the United

States, oil production declined 5% from 5.7 MMbd to 5.4 MMbd.

Falling production was attributed to field declines in Alaska and

the Gulf of Mexico coupled with a series of Gulf of Mexico hurricane-related shut-ins (0.1 MMbd or 38 million barrels). 

Refinery capacity use averaged 93% in 2004, essentially the same

State of the Markets Report • June 2005 227

Oil

Weekly U.S. Crude Oil Stocks

150,000

170,000

190,000

210,000

230,000

250,000

270,000

290,000

310,000

330,000

350,000

1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46 49 52

Weeks

Thousand Barrels

2004 Crude Stocks

5-year range

1999-2003

Weekly Distillate Stocks

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46 49 52

Weeks

Thousand Barrels

5-year range

1999-2003

2004 Distillate

Stocks

Oil Spare Capacity and Prices

0.00

10.00

20.00

30.00

40.00

50.00

60.00

01234567

OPEC Spare Capacity (Million barrels per day)

WTI Prices ($/BBl)

WTI $/barrel prices

Source: Derived from International Energy Agency, http://omrpublic.iea.org, Oil

Market Reports, February 2002 through February 2005 and derived from Bloomberg,

L.P. data. 

Source: Derived from EIA data.

Source: Derived from EIA data.
228 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Oil

1 Minerals Management Service Hurricane Ivan evacuation and

production shut-in statistics as of January 3, 2005. 

2 Ibid., September 16, 2004.

3 “Oil Market Outlook: ‘New Paradigm’ or Top of the Cycle?,”

Lehman Brothers, October 2004.

4 Members consist of Algeria, Indonesia, Iran, Iraq, Kuwait, Libya,

Nigeria, Qatar, Saudi Arabia, the United Arab Emirates, and

Venezuela.

5 Spare capacity is defined as the difference between OPEC 

member country actual production and sustainable production,

or the amount of production that can be achieved in 30 days

and then sustained for 90 days. 

6 “Oil Market Report, Monthly Oil Market and Stocks

Assessment,” International Energy Agency, April 12, 2005.

7 OMOI analysis of EIA data.

8 EIA Electric Power Monthly, March 2005.

9 “2004: A Sign of the Future for Refiners?,” a presentation at

the NPRA Annual Meeting, March 2005, EIA. 

Disclaimer: This report contains analyses, presentations and 

conclusions that may be based on or derived from the data sources

cited, but do not necessarily reflect the positions or recommendations

of the data providers. 

Endnotes

as in 2003. In August, U.S. refinery use reached 97%, its highest

point since August 1998. Operable refining capacity has been

growing for the past decade and grew 1% in 2004. Expansion is

likely to continue as product margins remain favorable and the

balance of consumption and production remains tight. Domestic

and worldwide demand for refinery products is growing faster

than refinery capacity, however, and the situation will worsen if

the rate of demand growth continues.9

The availability of OPEC spare capacity influenced WTI prices.

Average WTI prices increased from about $38/bbl to $55/bbl as

average OPEC spare capacity declined from 2 MMbd in 2003 to

1.25 MMbd in 2004. Spare production capacity averaged as little

as 0.35 MMbd between August and October. 
2004 was the nation’s 24th warmest year on record.1

Three states, Washington, Oregon, and Idaho,

had average annual temperatures close to record highs, while

most states saw above normal temperatures for the year. Only

Maine was below normal. Figures show that the last five pentads, or 5-year periods (2000–2004, 1999–2003, 1998–2002,

1997–2001, 1996–2000), were the warmest in the last 110 years

of record-keeping and include 1998, the warmest year on

record. By comparison, the sixth warmest pentad was during

1930–34, when the western United States had an extended period of drought and warmth. Last year was also the sixth wettest

on record for the nation as a whole, following a record wet year

in 2003. Thirty-four states recorded above average precipitation

for the year. Four states—Washington, Montana, Wyoming,

and Maine—were drier than average.

A Brief Seasonal Look

The winter of 2003–04 had near-average temperatures for the

nation as a whole, with the eastern seaboard near normal and the

central United States warmer. The major event of the winter was

the cold snap in New England (see New England essay).

Although this episode was serious for the region at the time, it had

little overall effect on the warm national winter. 

The 2003–04 snow season saw generally below-average snowfall

across much of the West. Above-normal snow was recorded early

in the season, but rapid snowmelt during a warm spell in late winter led to some loss of snowpack before the end of the western

snow season. This resulted in below-average end-of-season snowpack totals. Snow totals were also below normal for much of New

England, the lower Great Lakes area (especially around Chicago),

and the southwestern Great Plains states. Above-average snow

totals occurred along the Appalachian Range and parts of the

northern Great Plains. 

During spring 2004, every state but Florida recorded warmer-than

average temperatures. Overall, spring 2004 was the fourth

warmest on record for the nation. Summer 2004, on the other

hand, had temperatures well below average, ranking as the ninth

coolest summer in 110 years of record-keeping.2 The cool weather affected the much of the eastern two-thirds of the country;

while the west coast states were warmer than average. Eight states

in the central United States experienced a summer that was much

cooler than average. Another 22 states, from Montana to Texas

and eastward to the Mid-Atlantic, plus some states in the

Weather 

State of the Markets Report • June 2005 229

Pacific

Mountain

West N. Central

West S. Central

East S. Central

East N. Central

New England

Mid-Atlantic

South Atlantic

West N. Central

East N. Central Mid-Atlantic

New England

South Atlantic

East S. Central

West S. Central

Mountain

Pacific

94%

4,382

101%

4,709

100%

4,680

U.S. Total

95%

3,373

103%

3,659

100%

3,554

88%

2,082

104%

2,462

100%

2,361

98%

3,493

104%

3,709

100%

3,557

98%

5,448

105%

5,873

100%

5,577

100%

5,974

105%

6,307

100%

5,997

92%

5,958

99%

6,369

100%

6,464

95%

4,879

95%

4,853

100%

5,124

88%

2,379

91%

2,461

100%

2,702

93%

5,751

102%

6,272

100%

6,169

% of

normal

% of

normal

% of

normal

This

year

(CDD)

Last

year

(CDD)

Normal

(CDD)

Source: Derived from NOAA data.

Heating Degree Days
230 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Northeast, had seasonal temperatures significantly cooler than

average. The fall, on the other hand, was the 12th warmest on

record with many states in the central United States, from the

Great Lakes and northern Plains to the Gulf Coast, recording

near- record average temperatures.

Besides the cold snap in the Northeast during January 2004, the

major energy-related weather event of the year was Hurricane

Ivan. The storm became a tropical depression off the coast of

West Africa on August 31 and was a rare, category 5 hurricane

when it reached Jamaica on September 9. Hurricane Ivan moved

through the central Gulf of Mexico with sustained winds of up to

140 miles per hour, directly affecting many oil and gas platforms

off the shores of Louisiana, Mississippi, and Alabama (see discussion in natural gas section).3 Wave heights reportedly reached

nearly 90 feet before Hurricane Ivan made its United States landfall near Gulf Shores, Ala. on September 16. 

In general, the Atlantic hurricane season was more active than

average with 15 tropical storms and 9 hurricanes, including 6

major hurricanes. The season was also the most costly hurricane

season on record with damage estimated at $42 billion for the

United States.4

Weather Review

1 National Oceanic and Atmospheric Administration (NOAA),

“Climate of 2004-Annual Review, U.S. Summary,” National

Climatic Data Center, January 13, 2005. Data for 110 years.

2 NOAA defines summer as the period from June through August.

3 See a further discussion of Hurricane Ivan’s effect on oil and

gas production in the Gulf of Mexico in the Southeast regional

section of this report.

4 NOAA,“Climate of 2004 - Annual review, U.S. Summary,” 7.

Disclaimer: This report contains analyses, presentations and 

conclusions that may be based on or derived from the data sources

cited, but do not necessarily reflect the positions or recommendations

of the data providers. 

Endnotes

102%

1,111

105%

1,141

100%

1,091

U.S. Total

84%

760

103%

936

100%

908

85%

590 91%

630

100%

696

97%

627 102%

658 100%

648

96%400 100%

418 120%500

108%

1,733

101%

1,630

100%

1,612

105%

1,473

101%

1,413

100%

1,403 99%

2,118

105%

2,256

100%

2,149

111%

1,284

125%

1,443

100%

1,153

125%

802 122%

783 100%

641

West N. Central

East N. Central

Mid-Atlantic

New England

South Atlantic

East S. Central

West S. Central

Mountain

Pacific

% of

normal

% of

normal

% of

normal

This

year

(CDD)

Last

year

(CDD)

Normal

(CDD)

Pacific

Mountain

West N. Central

West S. Central

East S. Central

East N. Central

New England

Mid-Atlantic

South Atlantic

Cooling Degree Days

Source: Derived from NOAA data.
I

n 2004, wind became the fastest growing fuel

type for electricity generation in the United

States, with an average annual growth rate

exceeding 27%, starting with a small initial base

of 2578 MW in 2000. The Federal Production

Tax Credit (PTC) has played an influential role

in wind production. In the past, lapses in the tax

credit have created a boom-bust cycle in wind

project installation.1

Federal Policies

Wind project installation was weak in 2004.

Investment strengthened after Congress

renewed the PTC in October. Its renewal set off

a flurry of new wind generation project

announcements. Within a month, five utilities

and their affiliates announced fully permitted

facilities totaling 829 MW. The American Wind

Energy Association (AWEA) expected somewhere between 2,000 MW and 2,500 MW to be

Wind Review

State of the Markets Report • June 2005 231

1,000-2,100

100-1,000

20-100

1-20

Alaska - 1

Hawaii - 9

Total U.S. - 6,740 MW Wind Power Capacity (MW)

OH

TX

NM

OK

CO KS

NE

WY

SD

MT ND

WA

OR

CA

MN

IA

WI

IL

TN

MI

PA

NY

WV

VT

MA

240

263

2096

267

229

285

2 66

44

14

114

176

1293

29

51

632

615

53

2

7

66

129

48

6

1

Source: AWEA.

United States 2004 Year End Wind Power Capacity (MW)

Actual Expected Growth rate

2003 2004 2005 2000-2004

Capacity, MW (AWEA)

U.S., total installed 6,374 6,740 8,740 - 9,240 27.2%

Annual additions 1,696 389 2,000 - 2,500

MW top 5* states: 4,656 4,921 

Top 5 as % of installed wind 73% 73%

Generation, MWh (EIA)

Wind generation (utility & non-) 11,187 14,153 26.1%

Wind generation as % of total 0.29% 0.36% 24.5%

Net Summer Capacity MW (EIA)

Total MW 948,446 967,895

Wind MW 5,995 6,384

Wind as % of total 0.6% 0.7%

* (CA, TX, MN, IA, WY)

Source: Derived from data from the American Wind Energy Association (AWEA), Energy Information

Administration (EIA) Monthly Energy Review and preliminary unpublished data, NREL, and Platts PowerDat.

2004 capacity is net summer capacity.

United States Wind Supply-Demand Statistics
232 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

installed in 2005.2 At 1.9¢/ kWh3, the PTC applied to projects

on line by the end of 2005, and each credit was valid for 10 years

from the date of initial operation. 

States, meanwhile, increased their promotion of renewable

energy through renewable portfolio standards (RPS) and incentives that included loan funds, grant programs, tax exemptions,

net metering, and green-power purchasing programs. 

Accordingly, the Commission has sought to promote cooperation between federal and state authorities and regional transmission organizations through its policies on transmission and

wholesale markets. FERC held two technical conferences in

20044

—one to re-examine its rules on wind interconnection and

a second on wind transmission in wholesale markets—to ensure

that its rules did not inadvertently erect barriers to new technologies or intermittent resources. 

State Policies

As of 2004, 18 states and the District of Columbia had enacted

an RPS; nine of these standards were passed or amended that

year.5 An RPS requires electricity suppliers to add renewable

resources to their generation supply from eligible resources,

usually at a rate that increases yearly until a goal is met. The

goal may be relative to a supplier’s peak demand, or an absolute

amount of capacity. A few RPS have specified a percent of the

total that must be met using a particular fuel, such as wind or

solar power. States have enacted these standards to encourage

fuel diversity, lessen dependence on fuel imports, acknowledge

public environmental concerns, and meet more stringent

Environmental Protection Agency (EPA) emission requirements. Wide variation exists regarding the duration of these

standards, the share of renewables as a portion of the goals, and

the fuels that are included. Some states offer “extra credit” for

the use of certain renewables.

Many states with RPS have authorized related renewable energy credits (REC) and a trading mechanism. Creating a secondary market for credits separate from the energy commodity

makes the RPS more fungible. RECs give retail suppliers flexibility on how to comply with an RPS, depending on their skill

or business plan. Suppliers can demonstrate through ownership of a REC that they have generated, contracted for, or traded to achieve the required percent of renewables. Rules also

vary as to credit duration and whether the renewable source

must originate in the state itself or in the general region. As

more states enact RECs, many are working together to create

regional electronic tracking and verification systems.

Challenges to Wind Generation Development

Costs and Financing. Recent technological advances allowed

wind turbines to generate electricity for 4 to 6¢/kWh, apart

from any government subsidy or incentive. With subsidies in

place, new, large-scale wind projects could sell power to utilities

for somewhere between 2.5 and 3.5 ¢/kWh.6 Given 2004 natural gas prices and wind subsidies, the levelized cost of building a

new wind generation plant on a $/MWh basis compared favorably with the cost of a new gas-fired plant.7

In common with all generation technologies, wind developers

had to secure long-term power purchase agreements, usually

for 10–20 years, to obtain financial backing. When the Public

Utility Regulatory Policy Act encouraged early wind development, long-term contracts were guaranteed as an incentive.8

Today, most wind farms are built either as merchant facilities or

in response to a utility’s request for proposal for wind power.

Though some states have required or encouraged long-term

contracts, their absence elsewhere has continued to be a barrier

to financing and development. 

Location and Transmission Capacity. Wind generators produce and are paid only when the wind blows, so the nature of

transmission rules and services are important to generators.

The intermittent nature of wind compared with other technologies can present challenges to systems operations. FERC

and many independent system operators are addressing these

concerns through proposed reliability rules for wind. One way

to minimize the impact of intermittency is through better forecasting.

Wind generation is generally sited in high-wind resource areas,

which can be far from load. Often, transmission must be built

from generation to load areas. The need for transmission

investment raises questions of cost allocation and siting.

Transmission capacity and capacity credit for wind are issues

that states, public power authorities, regional coalitions, and

independent system operators are beginning to address.

Wind Review
Potential for Wind

Optimal wind resources are not evenly distributed across the

United States. Areas in the West and the Midwest have the

best wind potential, usually classified as wind class 3 sites and

above (See map page 234). 

Through 2004, installations were negligible in some states with

the highest potential for wind capacity. To illustrate the gap,

the top 20 states with the most wind potential are plotted

against their installed capacity. States in green had an RPS; the

others did not, underscoring the ongoing importance of government policy in fostering wind development. 

States with an RPS have more installed wind relative to their

wind potential (See chart at right).

State of the Markets Report • June 2005 233

Wind Review

-200

0

200

400

600

800

1,000

1,200

1,400

- 500 1,000 1,500 2,000 2,500

Installed Wind Capacity (MW)

Wind Potential in Billions kWh 

No RPS

State RPS

ND

KS

MN

IA

 OR

TX

CA

SD

NE

WY

WA

NM

OK

CO

NY WI

WV

Source: Derived from data from Lawerence Berkley National Laboratory (LBNL) wind

resources, AWEA database of installed wind resources, and various state websites. 

Leading Wind Power owners, cumulative 2003 (MW) 2003 (%) 2004 (MW) 2004 (%)

FPL Energy 2,700 42% 2,758 41%

Shell Wind Energy 393 6% 315 5%

AEP 310 5% 311 5%

enXco 238 4% 298 4%

PPM Energy 201 3% 225 3%

Top 5 Owners 3,604 57% 3,907 58%

Total U.S. MW Installed 6,372 6,740 

Leading Wind Turbine Manufacturers: US Sales 2003 (MW) 2003 (%) 2004 (MW) 2004 (%)

GE Energy 903 54% 171 44%

Mitsubishi 201 12% 120 31%

Vestas 359 21% 97 0%

NEG Micon (now Vestas) 129 8% N/A N/A

Gamesa 56 3% 0 0%

Bonus (now Siemens) 0 0% 0 0%

Top 5 Manufacturers 1,463 87% 388 99.9%

Total U.S. Turbine Sales 1,687 389 100%

Utilities / power companies buying the most windpower:

(output from installed MW) 2003 (MW output) 2003 (% U.S.) 2004 (MW output) 2004 (% U.S.)

Southern California Edison 1,080 17% 1,025 16%

Xcel Energy 829 13% 884 14%

Pacific Gas & Electric 680 11% 680 11%

PPM Energy 606 10% 606 10%

TXU 580 9% 580 9%

Top 5 wind-power purchasers 3,775 59% 3,775 59%

Total U.S.: MW installed 6,372 6,740

Source: Derived from AWEA project database, as of December 31, 2004.

Top 20 States by Installed Capacity (MW)

Capacity and Concentration of Leading Wind Companies in the U.S.
234 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Wind Review

1 The PTC lapsed in 2000, 2002, and 2004, with corresponding

drops in wind project installation in those years.

2 AWEA press releases, January 27, 2005 and April 26, 2005.

3 Initial Authority: 26 USC § 45; reauthorizing authority: H.R.

1308, the “Middle Class Tax Bill,” October 4, 2004. In 1992, the

Energy Policy Act created the production tax credit for wind

projects and set the amount at 1.5¢/kWh, to be adjusted for

inflation. Subsequently, the Internal Revenue Service adjusted

the PTC for inflation to 1.9¢/kWh for all projects placed into

operation in 2005. 70 Fed. Reg., 18,071, April 8, 2005. 

4 Technical Conference on Interconnection for Wind Energy and

Other Alternative Technologies, Docket Nos. PL04-15-000, et al.,

September 24, 2004; and Technical Conference on Assessing

the State of Wind Energy in Wholesale Electricity Markets

(Docket No. AD04-13-000), December 1, 2004. 

5 States that passed or amended their RPS in 2004 included

Colorado, Hawaii, Maryland, New Jersey, New Mexico, New York,

Pennsylvania, Rhode Island, and the District of Columbia (which

passed an RPS in 2004 and signed it in 2005). 

6 Ryan Wiser, LBNL, email correspondence, November 2004. 

7 Mark Bolinger, LBNL, “State Policy Impacts on Wind Project

Financing,” presented at the AWEA Wind Power Finance &

Investment Workshop, September 28, 2004; updated by correspondence, April 2005. LBNL analysis based on data from EIA’s

Assumptions to the Annual Energy Outlook 2005 and Nymex

closing prices, April 1, 2005. 

8 PURPA: 16 U.S.C. §824a-3, 796(17-22) (1982)

Disclaimer: This report contains analyses, presentations and conclusions that may be based on or derived from the data sources cited, but

do not necessarily reflect the positions or recommendations of the

data providers. 

Endnotes

Source: Department of Energy, National Renewable Energy Laboratory

http://www.nrel.gov/wind/wind_map.html

United States Wind Resources by Wind Class
State of the Markets Report • June 2005 235

OTHER MATERIAL

Glossary • Acronyms

Analytic Note on Net Revenue Calculations

Acknowledgments • Contacts

Evaluations Form
236 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

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: For the purposes of this report, the time

period between January 1, 2004, and December 31, 2004.

Automated mitigation control:A procedure under which the

bids of individual suppliers would be capped under certain predetermined 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. 

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. 

Availability: The maximum load-carrying ability of a generator,

exclusive of station use and planned, unplanned, or other outage;

or derating.

Balancing: The requirement imposed by electricity grids or natural gas pipelines that supply and demand be equal over a certain

time period. 

Baseline: In electric markets, refers to an agreed-upon level of

electricity consumption from which deviations are measured.

Usually based on a customer’s historical usage. Variations may be

billed at a different rate. 

Baseload: The minimum level of electric power demand of a

utility, region, or utility customer delivered or required over a

given period of time at a steady rate; generally expressed in units

of kilowatts or megawatts. The minimum continuous load or

demand in a power system over a given period of time. 

Baseload Unit: An electric power plant, or generating unit

within a power plant, that is normally operated continuously to

meet the base load of a utility.

Basis: The difference in prices between identical products but in

two different markets (in this report, different geographical natural gas markets). 

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 a broker

outside of a centralized power pool or power exchange. 

Bus:A conductor or group of conductors that serves as a common

connection for two or more electric circuits within a station. 

Capacity factor: A value used to express the average percentage

of full capacity used over a given period of time. For example, a

generating facility that operates at an average of 60% of its normal

full capacity over a measured period has a capacity factor of 0.6 for

that period. Can apply to an individual generating unit or a collection of them. Capacity factor is the ratio of the gross electricity

generated over a year to the energy that could have been generated at continuous full-power operation during the year.

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: 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. 

State of the Markets Report • June 2005 237

Glossary
238 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Coalbed methane: An unconventional gas produced from

gaseous beds or layers of coal ranging from brown coal (lignite) to

bituminous coal. Coalbed wells are drilled and usually completed

open-hole as opposed to cased and perforated, as done in a conventional natural gas well.

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. 

Combined-cycle power plant: A power plant that uses two

different thermal cycles for producing electricity. The first cycle

burns a fuel inside a gas turbine, and the gas turbine drives an electric generator. The hot air coming out of the gas turbine is used to

turn water into steam, and the steam turns a second electric generator. Combined-cycle power plants are the most efficient technology currently available for turning a fuel into electricity. They

can use a wide variety of liquid and gaseous fuels, but almost all

such plants in the United States burn natural gas.

Combustion turbine power plant: A combustion turbine

burns a fuel to produce a large volume of hot air, which then goes

through a series of precision fan blades, which convert the energy

of the hot air to rotate a shaft. The shaft, in turn, is connected to

an electric generator. The technology is closely related to that used

in the jet engines of airplanes. Such plants can be built at a lower

cost than other large power plants, but they are relatively inefficient in converting fuel into electricity.

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

electricity 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: 

• 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)

• Maintain, within the limits of Good Utility Practice,

scheduled interchange with other Control Areas

• Maintain the frequency of the electric power system(s)

within reasonable limits in accordance with Good Utility

Practice

• 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 to be supplied the following day. This market closes with acceptance by the

independent system operator, power exchange, or scheduling

coordinator of the final day-ahead schedule.

Debt financing: Providing the necessary capital by selling

bonds, bills, or notes to individuals or institutions. 

Demand: Represents the requirements of a customer or area at a

particular moment in time. Typically calculated as the average

requirement over a period of several minutes to an hour, and thus

usually expressed in kilowatts or megawatts rather than kilowatthours or megawatt-hours. Demand and load are used interchangeably when referring to energy requirements for a given

customer or area.

Demand elasticity: The demand response, or lack thereof, of

customers as a result of a change in price.

Demand responsiveness/demand response: A situation

Glossary
that occurs when customers respond to an increase in price 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. 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. It was

concluded that energy could be offered at higher prices than on a

cost basis as long as:

• Suppliers assume the risk of being out of merit

• If offered in such a way that it does not preclude a market

response. 

Electronic trading platform: An electronic system that

attempts to eliminate third-party orders entered by an exchange

market maker or an OTC market maker and permits such orders

to be executed in whole or in part. The platform allows major brokerages and individual traders to trade directly. 

Equity financing: The provision of needed capital through the

sale of common 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. 

First Contingency Reliability Criteria: An electric system is

planned and operated so that it can safely withstand the loss of the

largest single system element (i.e., power plant or transmission

line).

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 or a security are bought or sold. 

Gas turbine: See Combustion turbine power plant.

Generation: The act of producing energy, or the amount of

energy produced. A facility’s energy output is often referred to as

its generation. In measurement, generation is the gross amount of

electric energy produced minus the electric energy consumed at a

generating station for station use.

Generator: An electrical device used to convert mechanical

energy to electrical energy. The generator moves a conductor

through a magnetic field and directs the current produced by the

induced voltage to an external electric circuit.

Heat rate: A number that tells how efficient a fuel-burning

power plant is. The heat rate equals the Btu content of the fuel

input divided by the kilowatt-hours of power output. Heat rate is

expressed as the number of BTUs of heat required to produce a

kilowatt-hour of energy. Operators of generating facilities can

make reasonably accurate estimates of the amount of heat energy

of a given quantity of any type of fuel, which can be compared

with the actual energy produced. The resulting figure tells how

efficiently the generator converts fuel into electrical energy.

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. 

Hub: A geographical location where multiple participants trade

services. 

State of the Markets Report • June 2005 239

Glossary
240 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Independent market monitor: A party that identifies flaws

in market rules or other issues affecting market efficiency and

market power abuses. To ensure the independence of the monitoring function, the market monitor reports to the independent

board of directors of the RTO and FERC. 

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 October 31 period, during which gas is injected into natural gas storage reservoirs in

preparation for withdrawal and use during the winter heating

season.

Installed capacity:

• The total potential output of a given set of existing generators, usually measured in megawatts

• A share of potential (not actual) output that load-serving

entities are required to procure as an administrative measure to ensure adequate generation supply

See also locational installed capacity.

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 end-users 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 installed capacity (LICAP): Installed capacity in

a restricted location (e.g., New York City), rather than in a broader area (e.g., anywhere in New York State).

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 acceptance of delivery unless the contract is liquidated by an offsetting sale. 

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

futures contracts and cover changes in the value of futures contracts. 

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 – including a security such as a multiyear

contract – is adjusted to reflect current market value for the applicable period. 

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. 

Glossary
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. 

Market share analysis (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. 

Merchant generator: A generating plant built “on spec,” with

no energy sales contracts in place. Merchant plants will 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. 

Mothballed Capacity: A power plant that is out-of-service, but

is being maintained in such a condition that an operator can bring

it back into service.

Native load: Wholesale and retail customers that the transmission provider is obligated to serve.

Nitrogen oxide (NOx): NOx is a key pollutant in the formation of acid rain and ground-level ozone (smog). NOx also contributes to the formation of fine particles that are associated with

significant health effects and regional haze.

NOx Budget Trading Program (NBP): An ozone season capand-trade program intended to help states meet their NOx SIP

call required reductions. Twenty-one states and the District of

Columbia began participating in 2003-04 or will participate in the

future.

NOx State Implementation Plan (SIP): Building upon

analyses done by the Ozone Transport Assessment Group

(OTAG), this rule was finalized by the Environmental Protection

Agency (EPA) in 1998. It required states significantly contributing

to ozone nonattainment problems in other states to reduce their

NOx emissions during the ozone season beginning in 2003. This

rule gave states the flexibility to reduce emissions through various

means and gave them the option to participate in the NOx Budget

Trading Program.

Open access:

• Evolving access to a transmission system by all generators

and wholesale customers

• The use of a 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 marketplace, although with little or no regulatory oversight compared with an exchange or customized derivatives traded outside

of an organized exchange. 

Peak load, peak demand: These two terms are used interchangeably to denote the maximum power requirement of a system at a given time, or the amount of power required to supply

customers at times when need is greatest. Refers either to the load

at a given moment (e.g., a specific time of day) or to average load

over a given period of time (e.g., a specific day or hour of the day).

Usually expressed in megawatts.

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. 

Peakshaving LNG facility: A liquefied natural gas plant that

supplies a gas pipeline system during peak-use periods. During

slack periods the liquefied gas is stored. With the need for additional gas, the liquid product is gasified and fed into local distribution and gas pipeline systems. 

Plant factor: The capacity factor of an entire generating facility

including all available generating units. See also capacity factor.

Pivotal supplier: A power supplier whose capacity must be used

to meet peak demand and whose capacity exceeds the market’s

supply margin. 

Power purchase agreement: Guarantees a market for power

produced by an independent power producer and the price at

which it is sold to a purchaser. Such an agreement imposes legal

obligations on both the parties to perform previously accepted

tasks in a predetermined manner.

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.

State of the Markets Report • June 2005 241

Glossary
242 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Ramp rate: The rate at which a load on a power plant can be

increased. The rate for a hydroelectric facility may depend on how

rapidly water surface elevation changes on the river. 

Real-time market: An electric market that settles—determines

the price—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 a role similar to that of an independent system operator

but covering a larger geographical scale and involving both the

operation and planning of a transmission system. RTOs often run

organized markets for spot electricity.

Reliability must run (RMR): A unit that must run for operational or reliability reasons, regardless of economic considerations. 

Reserve margin:The percentage of installed capacity exceeding

the expected peak demand during a specified period. 

Retail unbundling: Disaggregating electric utility service into

its basic components 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. 

Safe harbor: The ability of management to discuss in good faith

a company’s prospects and financial projections with analysts and

investors without fearing litigation. 

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 delivery of the commodity unless the contract is liquidated 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 arbitrage

opportunity, using tolling or reverse tolling. 

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 usually organized markets for day-ahead and

real-time electricity 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. 

Steam plant: A plant in which the prime mover is a steam turbine. The steam used to drive the turbine is produced in a boiler

where fossil fuels are burned.

Sulfur dioxide (SO2): SO2 is a key pollutant in the formation

of acid rain and contributes to the formation of fine particles that

are associated with significant negative health effects and regional haze.

Swaps: An exchange of streams of payments over time according

to specified terms. A common type is a fixed-for-floating swap, in

which one party agrees to pay a fixed price in return for receiving

a changing price (e.g. spot) from another party. 

Time-of-use pricing: A rate design imposing higher charges to

customers during periods of the day when higher demand 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. 

Glossary
Transmission loading relief (TLR): Interrupts specific transmission flows or transactions and may curtail service to specific

customers or future transmission schedules. A TLR is called to preserve the reliability of the electric transmission system when electricity flows exceed permitted levels.

Transparency: A measure of the extent to which a market’s current trade and quote information is readily available to the public.

Turbine: A machine that converts the kinetic energy of a moving fluid to mechanical power by the impulse or reaction of the

fluid with a series of blades arrayed about the circumference of a

wheel or cylinder. 

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 day-ahead anticipated events, but what

actually occurs in real time—for example, generation or transmission trips, and changes in forecasted load. 

Unconventional natural gas: A term applied to natural gas

that is difficult and expensive to find and produce; if found, it

often is bypassed in favor of more easily obtainable supply that is

less costly to produce. Higher gas prices, however, increase the

interest in these more-costly gas sources. Examples of unconventional gas can be found in tight sandstone reservoirs and shale,

including the increasingly popular Barnett Shale in Texas.

Usage charge: Refers to charges levied on power suppliers or

their customers for the use of 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 traditional approach of telephone confirmation, etc. 

Volatility: A measure of the price fluctuation of an underlying

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 trade that is structured so that one company sells

power to a second company and then, at the same split second,

buys an equal amount of power from the second firm. Such trades

could be used to inflate market prices or traded volumes. The

trades potentially add directional momentum to the market and

increase sales volume and revenues of the company carrying out

the trades. 

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 November 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.

State of the Markets Report • June 2005 243

Glossary
244 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Acronyms

AEP American Electric Power Company

AMP Automated mitigation procedures

ARR Auction revenue rights

ATC Available transfer capability

AWEA American Wind Energy Association

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 independent system operator

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)

ESP Electric service providers

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)

HVDC High voltage direct current

ICAP Installed capacity

ICE IntercontinentalExchange

INC Incremental (energy)

INP Indian Point (nuclear plant in NYISO)

IOU Investor-owned utility

IPP Independent power producer

IRP Integrated resource plan

ISDA International Swap Dealers Association

ISO Independent system operator

ISO-NE Independent system operator-New England

JOA Joint operating agreement

kWh Kilowatt-hour (one thousand watt-hours)

LBMP Locational-based marginal price

LBNL Lawrence Berkeley Laboratory

LDC Local distribution company

LIPA Long Island Power Authority

LMP Locational marginal price/pricing

LNG Liquefied natural gas

LSE Load-serving entity

MAAC Mid-Atlantic Area Council (NERC region, 
State of the Markets Report • June 2005 245

Acronyms

geographically within PJM)

MAIN Mid-America Interconnected Network 

(NERC region)

MAPP Mid-Continent Area Power Pool (NERC 

region)

MISO Midwest Independent 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 ISONE and NYISO)

NREL National Renewable Energy Laboratory

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

PA Public power authority

PG&E Pacific Gas & Electric

PJM PJM Interconnection 

PPA Power purchase agreement

PSC Public service commission

PTC Production tax credit

PUSH Peaking Unit Safe Harbor

PX Power Exchange (formerly in CAISO)

REC Renewable energy credit

RMPA Rocky Mountain Power Area (NERC

subregion)

RMR Reliability must run

RPS Renewable portfolio standard

RSI Residual supply index

RT Real time

RTEP Regional Transmission Expansion Plan

RTO Regional transmission organization

RTS Real-time scheduling

SBC System benefit charge

SCADA Supervisory control and data analysis

SCE Southern California Edison

SERC Southeastern Electric Reliability Council 

(NERC region; includes Entergy, Southern, 

TVA, and VACAR)

SoCal Southern California Gas Co.
246 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Acronyms

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)
The State of the Markets Report includes analyses of net revenue for electric generators. In general, net revenue is the revenue that a hypothetical new plant could have earned from all

sources during the year less the running cost of operating the

plant. Comparing it to the annualized capital cost of building

such a new plant is a rough measure of the attractiveness of

investment.

We assumed the new facility would be a combined cycle or combustion turbine natural gas plant because those are normally

the most economic to build relatively quickly.

Revenues. In most cases, the bulk of the revenues for a hypothetical plant would come from the energy market. A plant can

earn money from the energy markets in all time periods when

the spark spread between natural gas and electric power prices

is above a break-even threshold, based mostly on the heat rate

of the plant. To estimate revenues, we:

• Calculated spark spreads as the difference between the spot

price of power and the spot price of gas in the region (as

reported in Platts Megawatt Daily and Gas Daily), multiplied

by the appropriate heat rate conversion in MMBtu/MWh.

• Assumed a heat rate of 7,000 MMBtu/MWh for combined

cycle plants and 10,500 MMBtu/MWH for combustion turbines.

• Subtracted an estimate of operation and maintenance

expenses of $1/MWH for combined cycle plants and

$3/MWh for combustion turbines.

• Summed all the positive results. This provides an estimate of

the amount of money the plant could have earned if it operated during all periods when it would have been profitable to

do so.

For regions with capacity markets (the northeastern RTOs), we

considered the revenue a plant could have made from the capacity market, based on prices published by the RTOs.

We did not include estimates of what a plant could have earned

from ancillary service markets. Except for combustion turbines

in New England, these revenues appear to be small compared to

the cost of a new plant. 

Cost of a New Plant. Estimates of the cost of building a new

plant vary widely. We used Energy Information

Administration (EIA) cost characteristics, combined with

regional adjustors as published in EIA’s Annual Energy Outlook

2005. These estimates tend to be lower than many estimates for

new plant costs. Based on discussions with EIA, we created

annual revenue targets for a new plant, assuming:

• A 45/55 debt/equity ratio

• 11.25 percent weighted average cost of capital

• 2 percent inflation

• 38 percent tax rate

• 20 year debt term

• 20 year depreciation term

• 16 percent return on equity.

Comparison. We divided the revenue estimate by the annual

target for a new plant to produce a ratio. This ratio indicates

whether a plant would have been profitable for 2004 – greater

than 100% would appear to have been profitable.

State of the Markets Report • June 2005 247

Analytic Note on Net Revenue Calculations
248 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations
Industry Overviews and Essays

The overviews were drafted by Charles Whitmore. Robert Flanders, 

Ted Gerarden, Thomas Pinkston, and Sebastian Tiger guided 

development of the essays, with contributions from John Kroeger, Eric Primosch,

Astrid Rapp, Steve Reich, and Charles Whitmore. 

Electric Power Markets

Dean Wight coordinated this section whose contributors were William Booth,

Keith Collins, Charles Faust, Alan Haymes, Lance Hinrichs, William Meroney,

Steven Michals, Astrid Rapp, Jeff Sanders, and Julia Tuzun. 

Natural Gas Markets 

Christopher Peterson coordinated this section with contributions and 

assistance from Robert Flanders, Ken Kohut, Gary Mahrenholz, Kamaria Martin,

Rafael Martinez, Kara Mucha, and Manali Shah. 

Other Market Factors 

The coordinators of Other Market Factors were Stacy Angel, Ken Kohut,

Christopher Peterson, Sebastian Tiger, and Carol White. Contributors included

Keith Collins, Ken Kohut, Gary Mahrenholz, Kamaria Martin, Kara Mucha, 

Tom Pinkston, Astrid Rapp, Jeff Sanders, Manali Shah, and Rahul Varma. 

Other Contributers

Other Commission staff who made major contributions to the report include

David Kathan, Matthew Deal, Jamie Simler, Marsha Gransee, Derek Bandera,

Raymond James and Jeff Wright. 

Production

Sidney Givens and Thomas Rieley checked report data. John Jennrich oversaw 

the editorial process with assistance from Jack Currie and Marie France. 

Judy Eastwood managed the graphic design with support from 

Terry Bazemore and Cecily Marx.

State of the Markets Report • June 2005 249

Acknowledgments

State of the Markets Report 

Preparation of the June 2005 State of the Markets Report placed serious demands on the

staff at the Office of Market Oversight and Investigations (OMOI), as well as on staff at the

Federal Energy Regulatory Commission at large. No acknowledgments can do justice to the

impressive efforts of so many people. Their contributions are gratefully received, 

nonetheless. Stephen Harvey directed the overall effort. Charles Whitmore and 

Stacy Angel provided day-to-day coordination of the project as a whole. 
250 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations

Executive Summary

Charles Whitmore 202-502-6256 charles.whitmore@ferc.gov

Markets Under Stress: New England Reacts to Record Cold

Robert Flanders 202-502-8442 robert.flanders@ferc.gov

Electric Markets Investment and Merger Trends

Sebastian Tiger 202-502-6079 sebastian.tiger@ferc.gov

Astrid Rapp 202-502-6264 astrid.rapp@ferc.gov

Improving Energy Market Information

Thomas Pinkston 202-502-6335 thomas.pinkston@ferc.gov

Charles Whitmore 202-502-6256 charles.whitmore@ferc.gov

Ted Gerarden 202-502-6187 ted.gerarden@ferc.gov

Steve Reich 202-502-6446 steven.reich@ferc.gov

John Kroeger 202-502-8177 john.kroeger@ferc.gov

Effectiveness of the Commission’s Market Behavior Rules

Ted Gerarden 202-502-6187 ted.gerarden@ferc.gov

Electric Overview

Charles Whitmore 202-502-6256 charles.whitmore@ferc.gov

Dean Wight 202-502-8835 dean.wight@ferc.gov

Keith Collins 202-502-6383 keith.collins@ferc.gov

New England Electric Market Profile

Julia Tuzun 202-502-8256 julia.tuzun@ferc.gov

Astrid Rapp 202-502-6264 astrid.rapp@ferc.gov

Keith Collins 202-502-6383 keith.collins@ferc.gov

New York Electric Market Profile

Dean Wight 202-502-8835 dean.wight@ferc.gov

Astrid Rapp 202-502-6264 astrid.rapp@ferc.gov

Keith Collins 202-502-6383 keith.collins@ferc.gov

PJM Electric Market Profile

Alan Haymes 202-502-6120 alan.haymes@ferc.gov

Astrid Rapp 202-502-6264 astrid.rapp@ferc.gov

Keith Collins 202-502-6383 keith.collins@ferc.gov

Midwest Electric Market Profile

William Meroney 202-502-8069 william.meroney@ferc.gov

Astrid Rapp 202-502-6264 astrid.rapp@ferc.gov

Keith Collins 202-502-6383 keith.collins@ferc.gov

Southeast Electric Market Profile

Lance Hinrichs 202-502-6438 lance.hinrichs@ferc.gov

Astrid Rapp 202-502-6264 astrid.rapp@ferc.gov

Keith Collins 202-502-6383 keith.collins@ferc.gov

Southwest Power Pool Electric Market Profile

William Booth 202-502-8849 william.booth@ferc.gov

Astrid Rapp 202-502-6264 astrid.rapp@ferc.gov

Keith Collins 202-502-6383 keith.collins@ferc.gov

ERCOT (Texas) Electric Market Profile

William Booth 202-502-8849 william.booth@ferc.gov

Astrid Rapp 202-502-6264 astrid.rapp@ferc.gov

Keith Collins 202-502-6383 keith.collins@ferc.gov

Northwest Electric Market Profile

Steven Michals 202-502-6373 steven.michals@ferc.gov

Astrid Rapp 202-502-6264 astrid.rapp@ferc.gov

Keith Collins 202-502-6383 keith.collins@ferc.gov

Southwest Electric Market Profile

Steven Michals 202-502-6373 steven.michals@ferc.gov

Jeff Sanders 202-502-6455 jeffrey.sanders@ferc.gov

Astrid Rapp 202-502-6264 astrid.rapp@ferc.gov

Keith Collins 202-502-6383 keith.collins@ferc.gov

California Electric Market Profile

Charles Faust 916-294-0163 charles.faust@ferc.gov

Steven Michals 202-502-6373 steven.michals@ferc.gov

Astrid Rapp 202-502-6264 astrid.rapp@ferc.gov

Keith Collins 202-502-6383 keith.collins@ferc.gov

National Gas Overview

Charles Whitmore 202-502-6256 charles.whitmore@ferc.gov

Robert Flanders 202-502-8442 robert.flanders@ferc.gov

Chris Peterson 202-502-8933 christopher.peterson @ferc.gov

Ken Kohut 202-502-6342 kenneth.kohut@ferc.gov

Kamaria Martin 202-502-8015 kamaria.martin@ferc.gov

Natural Gas Trading

Kara Mucha 202-502-6551 kara.mucha@ferc.gov

Northeast Natural Gas Market Profile

Chris Peterson 202-502-8933 christopher.peterson@ferc.gov

Ken Kohut 202-502-6342 kenneth.kohut@ferc.gov

Gary Mahrenholz 202-502-8229 gary.mahrenholz@ferc.gov

Kamaria Martin 202-502-8015 kamaria.martin@ferc.gov

Manali Shah 202-502-6259 manali.shah@ferc.gov

Southeast Natural Gas Market Profile

Chris Peterson 202-502-8933 christopher.peterson @ferc.gov

Ken Kohut 202-502-6342 kenneth.kohut@ferc.gov

Kamaria Martin 202-502-8015 kamaria.martin@ferc.gov

Manali Shah 202-502-6259 manali.shah@ferc.gov

Midwest Natural Gas Market Profile

Chris Peterson 202-502-8933 christopher.peterson @ferc.gov

Ken Kohut 202-502-6342 kenneth.kohut@ferc.gov

Kamaria Martin 202-502-8015 kamaria.martin@ferc.gov

Manali Shah 202-502-6259 manali.shah@ferc.gov

South Central Natural Gas Market Profile

Chris Peterson 202-502-8933 christopher.peterson @ferc.gov

Ken Kohut 202-502-6342 kenneth.kohut@ferc.gov

Kamaria Martin 202-502-8015 kamaria.martin@ferc.gov

Manali Shah 202-502-6259 manali.shah@ferc.gov

Western Natural Gas Market Profile

Chris Peterson 202-502-8933 christopher.peterson @ferc.gov

Ken Kohut 202-502-6342 kenneth.kohut@ferc.gov

Gary Mahrenholz 202-502-8229 gary.mahrenholz@ferc.gov

Kamaria Martin 202-502-8015 kamaria.martin@ferc.gov

Manali Shah 202-502-6259 manali.shah@ferc.gov

Contacts
2004 Coal Review

Chris Peterson 202-502-8933 christopher.peterson @ferc.gov

Kamaria Martin 202-502-8015 kamaria.martin@ferc.gov

2004 Oil Review

Chris Peterson 202-502-8933 christopher.peterson @ferc.gov

Ken Kohut 202-502-6342 kenneth.kohut@ferc.gov

Emission Allowance Markets

Stacy Angel 202-502-8019 stacy.angel@ferc.gov

Chris Peterson 202-502-8933 christopher.peterson @ferc.gov

Gary Mahrenholz 202-502-8229 gary.mahrenholz@ferc.gov

Wind

Carol Brotman White 202-502-6338 carol.white@ferc.gov

Demand Response

Stacy Angel 202-502-8019 stacy.angel@ferc.gov

David Kathan 202-502-6404 david.kathan@ferc.gov

Related Equity/Debt Markets

Astrid Rapp 202-502-6264 astrid.rapp@ferc.gov

Sebastian Tiger 202-502-6079 sebastian.tiger@ferc.gov

Eric Primosch 202-502-6483 eric.primosch@ferc.gov

Weather

Kenneth Kohut 202-502-6342 kenneth.kohut@ferc.gov

Analytic Note on Net Revenue Calculations

Charles Whitmore 202-502-6256 charles.whitmore@ferc.gov

State of the Markets Report • June 2005 251

Contacts
252 Federal Energy Regulatory Commission • Office of Market Oversight and Investigations
To improve future State of the Markets Reports we strongly encourage comments.

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Organization

Type of Organization

(e.g., state regulator, producer, consultant, 

generator, consumer advocate, lawyer)

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Contact information

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State of the Markets Report • June 2005 253

Evaluation Form

Please return form to the address below or e-mail comments to SOM.2004@FERC.gov.

OMOI (State of the Markets Report)

FERC • 888 First Street, N.E. • Washington, D.C. 20426

202-502-8100 • FAX: 202-502-6449