STAFF REPORT BY THE

OFFICE OF MARKET OVERSIGHT

AND INVESTIGATIONS

FEDERAL ENERGY

REGULATORY COMMISSION

ENERGY

MARKET

ASSESSMENT

J U L Y 2 0 0 3
TABLE OF CONTENTS

P R E F A C E

This market assessment reflects the ongoing 

commitment of the Federal Energy Regulatory 

Commission’s Office of Market Oversight and 

Investigations to identify and monitor the 

significant issues facing wholesale electric and 

natural gas markets.

The assessment focuses on electric and natural 

gas issues the nation’s energy markets face. 

While OMOI’s primary focus is real-time and 

after-the-fact market analysis, we use forwardlooking assessments to focus our monitoring 

efforts and to highlight opportunities for 

action by Commission, industry and other 

interested parties.

The Federal Energy Regulatory Commission 

created OMOI in April 2002 to focus its efforts 

in energy market oversight. Any errors are the 

responsibility of OMOI alone and not of the 

Commission as a whole.

We encourage readers to provide feedback on 

this OMOI product by sending comments to 

Energy.Assessment@ferc.gov, or by contacting 

staff listed in the acknowledgements. They can 

be reached as follows:

Office of Market Oversight and Investigations

Federal Energy Regulatory Commission

888 First Street, N.E.

Washington, DC 20426

(202) 502-8100

A fair energy marketplace is everyone’s 

responsibility. Please do your part. If you 

encounter inappropriate energy market 

behavior, contact our Enforcement Hotline 

toll-free by telephone at 1-888-889-8030 or via 

e-mail at hotline@ferc.gov.

Thank you.

WILLIAM F. HEDERMAN

Director

Office of Market Oversight and Investigations

EXECUTIVE SUMMARY.......................... 1

NATIONAL CHALLENGES

1. HIGH NATURAL GAS PRICES ................... 5

2. LACK OF DEMAND RESPONSIVENESS

 IN ELECTRICITY MARKETS .................... 15

3. FINANCIAL STRESS OF SOME NATURAL GAS

 AND ELECTRIC MARKET SECTORS............. 23

CONCLUSION .................................. 31

APPENDICES 

A. REGIONAL ASSESSMENTS ................... 33

  NEW ENGLAND ............................ 34

  NEW YORK................................. 36

  MID-ATLANTIC (PJM).................... 38

  SOUTHEAST (ENTERGY, SOUTHERN,

 TVA, VACAR, FRCC)................. 40

  MIDWEST (ECAR, MAIN, MAPP) ..... 43

  SOUTH CENTRAL (SPP)................... 45

  SOUTHWEST (AZ-NM-SNV

 AND RMPA).............................. 47

  NORTHWEST (NWPP).................... 49

  CALIFORNIA................................ 51

B. LIST OF ACRONYMS .......................... 55

C. GLOSSARY ................................... 57

D. FERC ENERGY MARKET

 PARTICIPANT INDEX ......................... 61

E. SELECTED NATURAL GAS

 AND ELECTRICITY PRICE POINTS............... 63

ACKNOWLEDGEMENTS ....................... 65
1

E N E R G Y M A R K E T A S S E S S M E N T

 National Challenges

In OMOI’s assessment, the three most pressing concerns for 

electric and natural gas markets currently are:

Challenge 1: High natural gas prices

A tight supply and demand balance in North 

America has driven natural gas prices significantly higher 

than year-ago levels. Recently, natural gas drilling has 

increased, but it is unlikely that new supply will moderate 

prices soon. Demand will remain relatively high compared 

to supply due to the twin uses of filling storage, which 

reached record lows this spring, combined with meeting 

demand for gas-fired power generation for cooling loads. 

Demand-side solutions, such as fuel switching and industrial demand responsiveness, will be less effective than in 

the past. How the public responds to pleas for conservation from Energy Secretary Abraham could play a key role 

in the near term.

High gas prices will challenge both electric and gas 

market customers in the near term. Electric markets, increasingly dependent on natural gas for a significant share of 

power generation fuel, will face increased prices. The extent 

of the burden depends primarily on weather conditions. And 

gas markets face the competing demands to use gas to serve 

electric customers and to use gas to fill storage for heating 

customers this coming winter.

Challenge 2: Lack of demand responsiveness in electricity markets

A lack of demand responsiveness in electricity 

markets costs customers in times of peak demand. When 

prices for electricity rise, few customers see this change in 

time to respond and, thus, do not have the opportunity to 

Executive

Summary ENERGY MARKET

ASSESSEMENT

H

igh reserve margins exist across much of the country. Market participants 

have taken steps toward transparent market designs and trading platforms as 

energy markets evolve. Industry has agreed to respond to concerns about gas 

price information. Despite recent financial problems, energy markets appear to be 

rebounding financially. 

Nevertheless, energy markets face national and regional challenges, which we 

examine in this report.
E N E R G Y M A R K E T A S S E S S M E N T

2

reduce their electricity use. During periods of transmission 

constraints or high demand, these prices can rise substantially. Rather than reducing supply to those customers who 

would prefer to reduce consumption rather than pay high 

prices, market operators must generate or buy sufficient 

electricity to meet total price-insensitive demand, raising 

costs for all customers. In addition, lack of demand 

responsiveness increases the ability of suppliers to exert 

market power and raise prices for all customers. 

Absent demand responsiveness, electricity markets 

face higher prices during periods of high demand and 

congestion. Though small reductions in demand during 

these times could lower electric prices significantly, this 

option is missing across most of the country. Customers 

need access to meaningful and accurate price information 

that reveals the value of electricity given the time and 

place of use. With this tool allowing customers to change 

their electricity usage in response to price, demand 

response could have a significant effect on electricity 

price levels, price volatility, system reliability and supplier 

market power. This is a more efficient means of meeting 

peak demand than purchasing electricity at peak prices. 

In the near term, the only likely meaningful effect on high 

and volatile electricity prices and supplier market power 

will result from policy leader exhortations for conservation, load shifting and other actions as a part of good 

energy citizenship.

Challenge 3: Financial stress of some 

natural gas and electric market sectors

Since 2001, large sectors of natural gas and electric 

markets have experienced a financial crisis accompanied by 

a loss of investor confidence, a dramatic decline in financial 

liquidity and project delays and cancellations. These 

problems have adversely affected customers by reducing 

the number of companies active in energy markets, consequently limiting market liquidity and effectiveness.

In the first half of 2003, while a few companies filed 

for bankruptcy, many companies in the beginning of the 

year negotiated debt-refinancing deals that allowed them 

additional time to implement revised business strategies and await improving market conditions. If financial 

conditions continue to improve, the industry can move 

into a new phase characterized by streamlined costs, 

a refocus on core business lines, continued improvements to balance sheets and, in some cases, a change 

in ownership, management and business strategies. 

The results should improve market liquidity over the 

longer term, making markets more efficient and giving 

customers choices.

Although the industry is still recovering from 

the loss of market capitalization incurred since 2001, it 

appears to have reached a new, reduced-value plateau 

that could be the starting point for future growth. For 

the FERC Energy Market Participant Index of more than 

90 companies (see Appendix D) as of June 20, year-todate market capitalization was up almost $34 billion, 

or 11 percent, compared to a loss of $91 billion, or 29 

percent, in 2002.

Because financial uncertainty continues, however, 

the industry and its customers must contend with 

shrinking physical and financial energy markets due to 

participants that have exited or scaled back trading. This 

contraction gives customers fewer choices and reduces 

market efficiency. Financial troubles can be accompanied by reduced capital expenditures and consequent 

operational difficulties. Finally, financial stress creates the 

incentive for potentially inappropriate interaffiliate cash 

management practices because the costs could be inappropriately borne by customers of regulated affiliates.

Regional Assessments

Currently, most electricity markets across the 

country have high reserve margins, which generally reduce prices. Nevertheless, there are issues of 

concern in each region that OMOI is monitoring. 

More detailed discussion of each region’s areas of 

concern appears in Appendix A, including reserve 

margins, natural gas and electric prices and maps. 

The matters of particular concern in each region that 

OMOI will monitor closely are:
E N E R G Y M A R K E T A S S E S S M E N T

3

New England

 Southwest Connecticut load pocket

 ISO-NE’s new market software

 Transmission constraints that prevent export of 

excess efficient generation

 Potentially high natural gas-driven electric prices

New York

 New York City load pocket

 Long Island load pocket

 Non-operational tie line between Long Island and 

Connecticut

 Gas deliverability constraints into the downstate area 

 Potentially high natural gas-driven electric prices

Mid-Atlantic (PJM)

 Congestion in the Delmarva Peninsula

 Congestion in northern New Jersey

 Constrained transmission lines or substations

 Wylie Ridge

 Bedington-Black Oak

 Doubs

 Erie West-Erie South

 East Towanda-North Meshoppen

 Seams problems related to coordination with other 

regions

 Potentially high natural gas-driven electric prices

Southeast (Entergy, Southern, TVA, 

VACAR, FRCC) 

 Gas deliverability constraints in Florida

 Constraints along internal interfaces, such as between 

Southern and the Tennessee Valley Authority

 Local transmission constraints

 Atlanta, Ga.

 Destin, Fla.

 Panama City, Fla.

 Constrained Cloverdale-Lexington transmission line

 Potentially high natural gas-driven electric prices

Midwest (ECAR, MAIN, MAPP)

 Load pocket in Wisconsin-Upper Michigan System

 Seams problems related to loop flow along Lake Erie 

with PJM

 Constrained transmission areas

 Eau Claire-Arpin

 Lore-Turkey River

 Northern Kentucky

 Poweshiek-Reasnor

 Michigan-Ontario interface

 North Platte-Stockville

 Potentially high natural gas-driven electric prices

South Central (SPP)

 Constrained interface between SPP and Entergy

 Constraints along LaCygne-Stilwell transmission line

 Other constrained transmission lines

 Phillips-South Phillips

 North Eastern-Oneta

 Craig Junction-Ashdown West

 Morrison-Stilwater

 Creswell-New Kirk

 El Paso-Farber

 Ft. Smith-ANO

 Potentially high natural gas-driven electric prices
E N E R G Y M A R K E T A S S E S S M E N T

4 

Southwest (AZ-NM-SNV and RMPA)

 Localized load pockets

 Phoenix, Ariz.

 Tucson, Ariz.

 Yuma, Ariz.

 Santa Cruz County, Ariz.

 Mohave County, Ariz.

 Southern Nevada, including Las Vegas

 Potentially high natural gas-driven electric prices

 Below-average hydro conditions

Northwest (NWPP)

 Late summer hydroelectric production 

 Potentially high natural gas-driven electric prices

California

 Various load pockets

 Greater San Francisco Bay Area

 Los Angeles area

 San Diego area

 Congestion due to equipment failure along Path 26, 

north-south transmission link

 Constrained import capabilities

 Southwest Power Link

 Southern California Import Transmission path

 California-Oregon Intertie

 Potentially high natural gas-driven electric prices

 Dispatch reliability issues
5

E N E R G Y M A R K E T A S S E S S M E N T

two issues, discusses how the 

industry is addressing them and 

presents Commission actions to 

address the issues. OMOI plans to 

monitor closely developments related 

to these issues.

 The Situation

Natural gas prices have moved 

to a new, potentially sustainable level 

above $4/MMBtu. Spot gas prices 

are holding at this high level and 

the average of the 12-month strip 

through July 2004 at the New York 

Mercantile Exchange (Nymex) is 

trading around $5.105/MMBtu. As 

shown in Figure 1-1, Nymex values 

for monthly contract settlement 

prices for the balance of 2003 are 

trading at 42 percent above the 

monthly contract settlement prices 

for the same months in 2002 and at 

approximately three times the price 

of those contracts during the early 

1990s.

A

tight supply and demand balance in North 

America has driven natural gas prices significantly higher than year-ago levels. Recently, 

natural gas drilling has increased, but it is 

unlikely that new supply will moderate prices soon. 

Demand will remain relatively high compared to supply 

due to the twin needs to refill storage, which reached 

record lows this spring, combined with meeting demand 

for gas-fired power generation for cooling loads this 

summer. Demand-side solutions, 

such as fuel switching and industrial demand responsiveness, will be 

less effective than in the past. How 

the public responds to pleas for 

conservation from Energy Secretary 

Abraham could play a key role.1

High gas prices will challenge 

both electric and gas market customers in the near term. Electric markets, 

increasingly dependent on natural 

gas for a significant share of power 

generation fuel, will face increased 

prices in the near term. The extent 

of the burden depends primarily on 

weather conditions. And gas markets 

face the competing needs to use gas 

to serve electric customers and to use 

gas to fill storage for heating customers this coming winter. 

This chapter presents these 

1

 Department of Energy, “Abraham Unveils Smart 

Energy Use Education Campaign,” press release, 

July 9, 2003.

Load, which is often 

synonymously used with 

demand, is the total 

amount of power carried 

by an electric system 

per unit of time.

Demand 

responsiveness/

demand response 

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. 

Spot market is 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 realtime electricity run 

by an independent 

system operator or 

regional transmission 

organization.

12-month strip

refers to the prices 

for the next 12 months 

of consecutive natural 

gas futures trading 

contracts, usually 

starting with the nearest, 

or prompt, month. 

HIGH NATURAL

GAS PRICES

Challenge 1
E N E R G Y M A R K E T A S S E S S M E N T

6

Figure 1-1

08-22-03

$12

$10

$8

$6

$4

$2

$0

Pric

e ($/M

M

Btu)

History Futures Prices

Jan ‘03Jan ‘91Jan ‘92Jan ‘93Jan ‘94Jan ‘95Jan ‘96Jan ‘97Jan ‘98Jan ‘99Jan ‘00Jan ‘01Jan ‘02Jan ‘04Jan ‘05Jan ‘06

Monthly Contract

Settlement Price

Futures

Settlement

Price

Figure 1-1: Henry Hub futures prices indicate that market participants expect real 

natural gas prices to remain well above prices of the early 1990s

Source: Historical data are Nymex settlement prices from GASdat, adjusted for inflation.

Futures prices are Nymex settlement prices on July 15, 2003.

Recently, natural gas drilling has increased, but it 

is unlikely that new supply will arrive quickly enough to 

moderate prices soon. The number of U.S. natural gas 

rigs drilling for gas increased 29 percent from January 1, 

2003 to July 11, 20032 showing that the market is responding effectively to price signals but U.S. natural gas dry 

production is down since 2001. It dropped from 19.68 Tcf 

in 2001 to 19.05 Tcf in 2002, a decrease of 3.2 percent.3

Well productivity has declined significantly and gas prices 

have risen in part because gas production costs are higher. 

Though demand has remained low — 2002 demand is 

slightly above 2001 demand and below 2000 consumption4

 — it remains high relative to supply.

Limitations exist in demand-side flexibility to buffer 

natural gas prices. Many industrial and power generation 

facilities that have been burning liquid fuels due to recent 

high natural gas prices may be nearing emissions limits.5

In addition, most of the new natural gas-fired generating 

units that have entered service since 2002 do not have 

backup fuel oil capability.6

Finally, a significant amount of price-sensitive 

demand declined prior to the heat of the summer. The 

chemical industry, the largest industrial natural gas 

consuming sector,7 has been reporting poor financial 

results due to weak product prices and high natural gas 

prices. Several firms have shut down or slowed production 

at U.S. plants.8 The story in fertilizer production, another 

large industrial user of gas, is much the same, with several 

U.S. firms in bankruptcy and others shifting much or all 

of their operations to Trinidad or the Middle East, where 

gas feedstock is cheaper than in the United States. Other 

industrial companies that use natural gas for power 

generation have invested in more efficient gas equipment 

Point,” monthly briefing, May 15, 2003, p. 3.

6

 POWERdat, July 31, 2003.

7

 Lehman Brothers, “Natural Gas: A Comprehensive Supply-Demand Analysis,” 

April 16, 2003.

8

 Carol Dudley, Dow Chemical Co., news conference, March 11, 2003.

2 www.bakerhughes.com, “U.S. Rotary Rig Count, Baker Hughes Oil-Gas Split.” 3

 Energy Information Administration (EIA), Summary of Natural Gas Production, 

Web file name: NGM01VMALL.xls.

4

 EIA, Short-Term Energy Outlook, Table 8, July 2003. 5

 Cambridge Energy Research Associates (CERA), “Oil and Gas at the Switch 
E N E R G Y M A R K E T A S S E S S M E N T

7

An electric 

generating unit is 

on the margin/the 

marginal unit if it is 

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.

9

 NEWGen, May 22, 2003.

10 Peter Augustini, CERA, personal correspondence, April 23, 2003.

11 Energy Information Administration (EIA), Annual Energy Report 2001, 

November 2002.

or installed equipment that uses an 

alternate fuel, reducing gas demand. 

Natural gas prices could 

drive electric prices higher in 

the near term. While a number of 

factors affect the final price of wholesale electricity, the price of natural 

gas is a major concern. A record level 

of incremental gas-fired generating 

capacity began commercial service in 

2002 — approximately 63 GW.9

There are now several regions 

of the country where natural gas 

fuels the marginal source of electricity for significant portions of the year, especially during 

the summer. Electricity customers in these regions will 

likely face high gas-driven power prices because the price 

of the marginal source of electricity sets the marketclearing price in organized electric markets. In Figure 1-2, 

Cambridge Energy Research Associates (CERA) forecasts 

that gas and oil will fuel the marginal generators in well 

over half of all peak hours for many regions.10 Note that 

oil is unlikely to make up a significant share of the hours 

represented in the graph because oil represented less than 

4 percent of total generation in 2001.11

Figure 1-2: Natural gas-fired generation often sets the regional wholesale electric price

Source: Cambridge Energy Research Associates (CERA)

Note: Percent of time natural gas or oil is projected to be on the margin during peak hours in 2003.

Pacific

Northwest

(87%)

(95%)

CA

(91%)

Mountain

Northwest

(60%)

VACAR

(27%)

Southern

(50%)

SPP

(47%)

AZ-NM-So. NV

(78%)

Mountain

Northwest

(60%)

Rocky

Mountains

(15%)

MAPP-US

(10%)

MAIN

(20%)

ERCOT

(86%)

NYPP

(49%) NEPOOL

(79%)

MAAC

(48%)

ECAR

(23%)

VACAR

(27%) TVA

(25%)

Southern

(50%)

FRCC

(92%)

Entergy

(58%)

SPP

(47%)

Figure 1-2

August 22, 2003

>50% - 75%

>75% - 100%

0% - 25%

>25% - 50%

Frequency (% of time)

that natural gas or oil

is the marginal fuel
E N E R G Y M A R K E T A S S E S S M E N T

8

Figure 1-3 shows that across the country, with one 

exception, early summer prices were higher than they 

were last year. Comparing June 2002 to June 2003 using 

these points, prices were up from 8 percent at ComEd 

in the Midwest to 243 percent at Mid-Columbia in the 

Northwest.

Figure 1-3: Electric prices were higher across the U.S. going into summer 2003 than summer 2002

Source: Megawatt Daily

Note: Prices shown are the volume-weighted, day-ahead, peak prices averaged for the month. 

For a map of price points, see Appendix E.

Figure 1-3

08-22-03

NEPOOL/Mass

Hub

New York, Zone

G

New York, Zone

J

PJM West

Entergy

Southern

Florida

Cinergy

ComEd

MAPP North

SPP

ERCOT

Palo

Verde

Mid-Columbia

NP15

SP15

June 2002

June 2003

$90

$80

$70

$60

$50

$40

$30

$20

$10

$0

Pric

e ($/M

W

h)
E N E R G Y M A R K E T A S S E S S M E N T

9

Figure 1-4: Natural gas prices are higher across the U.S. going

into summer 2003 than summer 2002

Source: Gas Daily

Note: Prices shown are volume-weighted, day-ahead, mid-point prices averaged over the month. For a map of price points, see Appendix E. Figure 1-4

08-22-03

Tenn., Zone

6

delivered

Transco, Zone

6 N.Y.

Transco, Zone

6

non-N.Y.

Henry

Hub

Transco, Zone

4

Florida

city-gates

Columbia

Gas, App.

Chicago

city-gate

Panhandle, Tx.-Okla.

Northern, demarc.

Houston

Ship

Channel

El Paso, San

Juan

Basin

Northwest (Sumas)

PG&E city-gate

SoCal Gas

$7

$6

$5

$4

$3

$2

$1

$0

Pric

e ($/M

M

Btu)

June 2002

June 2003

Figure 1-4 shows the increases in natural gas 

prices for the same time period, June 2002 to June 2003, 

for representative points across the United States. The 

numbers show that prices are up everywhere and that the 

increases range from 58 percent at Florida city-gates to 

131 percent at Northwest (Sumas).

Changes in natural gas prices can 

have pronounced effects on electricity production costs. The price of 

natural gas represents the largest 

component of cost for a gas-fired 

generator.12 For instance, the price 

of natural gas accounts for approximately 86 percent of the production 

cost for a generic 500-MW gas-fired 

combined-cycle plant with a 7,000 

Btu/kWh heat rate operating at a 

50 percent load factor.13 Other costs 

include variable operations and 

maintenance (O&M) expenses and 

transmission charges. Under these 

assumptions, a 50 percent increase 

in the cost of natural gas results in 

a 43 percent increase in the production cost of power, holding O&M and 

transmission charges constant. 

Not all generators’ production costs are affected equally by 

increases in natural gas prices. Some generators have 

hedged their gas-price risk. Hedging some or all of a 

Combined-cycle 

generators 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. 

Hedging is a risk 

management tool used 

to protect the value 

of an investment or 

contractual commitment 

from the risk of loss due 

to price fluctuations.

12 The price of natural gas may include charges for the following: gas commodity, all interstate pipeline transportation services and local distribution company 

services.

13 This calculation makes assumptions about O&M and transmission costs. It 

assumes the average monthly contract index settlement price of natural gas 

commodity at the Henry Hub for January through June 2003 of $5.88/MMBtu, 

a transmission charge of $4.11/MWh or (($1.50/kW-month x 500,000 kW) / 

((500,000 kW x 730 Hours in a Month x 50% Capacity Factor) / 1000)) and a 

variable O&M charge of $2.50/MWh. 
E N E R G Y M A R K E T A S S E S S M E N T

10

Gas on the margin: There are 

many regions where natural gas is 

the fuel on the margin for significant portions of the year. These 

regions are most at risk for high 

gas-driven power prices.

Availability of significant 

dual-fueled generation: Surveys 

of capacity indicate that existing 

dual-fueled generating capacity, estimated at 135–153 GW21, is located 

primarily in New England, New York 

and the Southeast. As discussed 

facility’s gas and other fuel needs through long-term 

contracts or options could play an important role in 

limiting some generators’ gas costs. In the past, public 

utility commissions (PUCs) have encouraged local distribution companies (LDCs) to benchmark to spot prices and 

avoid hedging. When PUCs encourage LDCs to hedge, they 

may protect customers with prudent hedging program 

guidelines.

The potential for high gas prices to affect electric 

prices is not the same across all regions of the United 

States. Major factors that influence regional vulnerability 

to high natural gas-driven electric prices are summarized in Table 1-1 and discussed below.

Share of regional generation that is gas-fired: 

A key factor affecting a region’s vulnerability to high 

electric prices as a result of high gas prices is the region’s 

dependence on natural gas, especially dependence on 

natural gas on the margin since marginal generators set 

the market-clearing price in organized markets. Table 1-1 

shows that natural gas fuels a large portion of capacity 

(greater than 50 percent) in California and a significant 

(25 percent to 49 percent) portion of generation in New 

England, New York, the Southeast, South Central and 

the Southwest. 

14 See maps of each region in Appendix A (Regional Assessments).

15 POWERdat, July 31, 2003. Qualitative labels are based on percentage of total 

capacity that uses natural gas as the primary fuel: 1%-24%, small; 25%-49%, significant; 50%+, large.

16 CERA, see Figure 1-2. Qualitative labels are based on percent of time gas or oil 

is projected to be on the margin in 2003: 1%-39%, no; 40%+, yes.

17 Ken Yeasting, CERA, phone conversation, July 23, 2003.

18 Derived from natural gas pipeline capacity data base provided by James Tobin, 

Energy Information Administration, April 2003. Estimates incorporate potential 

deliverability increases associated with liquefied natural gas (LNG) expansion 

facilities.

19 OMOI analysis.

20 OMOI analysis.

21 EIA; analysis derived from POWERdat, May 21, 2003.

A dual-fueled (or 

dual-fired) unit is 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.

Table 1-1: Major factors influencing regional vulnerability

to high natural gas-driven electric prices in summer 2003

Risk Factors

New 

England14 New York Mid-Atlantic Southeast Midwest

South 

Central

West -- 

Southwest & 

Northwest California

Share of regional 

generation that is 

gas-fired15

Significant Significant Small Significant Small Significant Significant in 

Southwest, small 

in Northwest

Large

Gas often on the 

margin?16

Yes Yes Mixed, varies 

by subregion

Mixed, varies by 

subregion

No Yes Yes, except in 

Rocky Mountains 

Yes

Availability of significant dual-fueled 

generation17

Yes Yes No Yes No No No No 

Recent and anticipated increases in pipeline deliverability18Yes, Tractebel 

LNG expansion 

(280 MMcfd)

No No Yes, 

FGT (41 MMcfd) 

No No No Yes,

Kern River (886 

MMcfd)

Likelihood of sustained, material gas 

pipeline constraints19

Unlikely Possible Unlikely Possible in 

Florida, unlikely 

in rest of 

Southeast

Unlikely Unlikely Unlikely Unlikely

Availability of 

hydroelectricity this 

summer20

n/a — hydro a 

low percent of 

generation

n/a — hydro 

a low percent 

of generation

n/a — hydro a 

low percent of 

generation

n/a — hydro a 

low percent of 

generation

n/a — hydro a 

low percent of 

generation

n/a — hydro a 

low percent of 

generation

Slightly below 

normal

Slightly below 

normal
E N E R G Y M A R K E T A S S E S S M E N T

11

previously, fuel switching, including fuel switching by 

industrial facilities, may be limited because of industry 

shutdowns, environmental regulations and the fact that 

loads able to switch already have.

Recent and anticipated increases in pipeline 

deliverability: Incremental gas pipeline capacity can 

reduce a region’s vulnerability to high gas-driven 

electric prices by increasing access to alternative gas 

supplies. Approximately 1.2 Bcfd of new gas pipeline 

and liquefied natural gas (LNG) deliverability will soon 

enter service in the United States. Key infrastructure 

projects beginning service are shown in Table 1-1.

These recent pipeline expansions build upon approximately 10 Bcfd of new interstate natural gas pipeline 

capacity completed in 2002. 22

Likelihood of sustained gas pipeline constraints: 

Conversely, constraints at key receipt or delivery points 

on natural gas pipelines can increase gas prices delivered into a region and potentially lead to increased 

electric prices. Despite increases in pipeline deliverability, constraints along segments of key pipelines remain 

possible. To date, the Florida market has occasionally 

been affected by pipeline constraints on Florida 

Gas Transmission’s (FGT’s) summer-peaking system. 

However, FGT’s system reportedly 

has adequate deliverability to meet 

firm shipper deliveries due to its 

continuing expansion efforts and 

enhanced flexibility stemming 

from downstream receipt point 

access on the Gulfstream Natural 

Gas System,23 which came on line in summer 2002. 

High natural gas load on the Transcontinental Gas 

Pipe Line Corp. system is unlikely to compromise 

the reliability of transportation into New York City in 

the near term due to the availability of market area 

storage.24 However, pipeline constraints could arise due 

to coincidental hot weather, storage injections and fuel 

use limitations.

Near term availability of electricity from hydro 

sources: A region’s vulnerability to high gas-driven 

electric prices is affected by the availability of electricity produced using other sources. The Northwest 

continues to have slightly below-normal levels of water 

in its hydroelectric network.25 Imports by California 

from the Pacific Northwest are likely to be 85 percent 

of normal,26 but the shortfall in 

California will be supplemented 

by hydroelectricity produced from 

healthy in-state hydro conditions. 

The Southwest, though less dependent on hydroelectric generation 

than the rest of the West (about 15 

percent of total regional capacity),27

continues to experience drought 

conditions, and generation from 

the Colorado River and its tributaries will be below 

normal so more natural gas will be needed to meet its 

energy supply needs. 

High natural gas prices and competition for 

gas to fuel generation influence storage injection plans and leave storage levels low entering 

the 2003-04 heating season. Storage stocks ended 

the 2002-2003 winter heating season well below the 

five-year average of 1,187 Bcf, 54 

percent below the year-ago level 

and at the lowest aggregate inventory level in March recorded by 

EIA in nine years. The producing 

and eastern consuming region 

stocks were at record lows. Storage 

levels in the West are not as low as 

elsewhere. As shown in Figure 1-5, 

national storage levels at the beginning of the injection season in 

April continued at historical lows, 

but in May, June and early July, 

storage holders made repeated, 

substantial injections into storage. 

To reach the industry’s 2,700-3,000 Bcf “comfort 

level” for the end of the injection season on October 31, 

storage must refill at an accelerated rate. This “comfort 

level” is necessary to ensure that gas supply in the United 

Firm transportation

or deliveries are 

guaranteed not to be 

interrupted.

Winter heating season 

refers to the November 

1 through March 31 

period, during which 

most natural gas use 

for space heating 

takes place.

Injection season refers 

to 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.

22 Derived from natural gas pipeline capacity database provided by James Tobin, 

EIA, April 2003. Estimates incorporate potential deliverability increases associated with expanded LNG facilities.

23 Personal communication with FGT market and system planning personnel, 

May 30, 2003. 

24 Transcontinental Gas Pipe Line Corp., “Daily Operational Information,” electronic bulletin board, June-July 2003.

25 National Oceanic and Atmospheric Administration (NOAA), National Weather 

Service, Northwest River Forecast Center (NWRFC), http://www.nwrfc.noaa.gov/.

26 Office of Energy Projects analysis.

27 Office of Energy Projects analysis.
E N E R G Y M A R K E T A S S E S S M E N T

12

States can meet demand even if extreme weather or physical 

operations problems occur. As of July 4, in order to reach 

3,000 Bcf by October 31, injections need to be 2.2 Bcfd more 

than average, or roughly 20 percent of daily demand during 

the remainder of the injection season.28 LDCs control almost 

three-fourths of storage capacity in the United States.29 FERC 

has alerted public utility commissions (PUCs) to the gas 

storage challenge and the PUCs will likely encourage LDCs 

to purchase gas and fill storage, even though prices are high, 

because LDCs have an obligation to serve their customers 

whose health and safety are at stake. The remaining onefourth to one-third of storage is of most concern.

Refilling low storage volumes while still meeting 

electric generation fueling needs will be more difficult than 

in the past. The distressed condition of the merchant energy 

sector likely will affect total working gas in storage as energy 

companies reduce positions in the gas market, reduce marketing and trading activities and reduce the number of assets and 

physical supply necessary to support such operations.30

Figure 1-5

08-22-03

3,500

3,000

2,500

2,000

1,500

1,000

500

0

Volume (Bcf)

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

5-year range

2001–2002

2002-2003

2003-2004

U.S. Total

Figure 1-5: National natural gas storage level

Source: EIA, “Historical Weekly Storage Estimates Database,”

Weekly Natural Gas Storage Report; data through the week ending July 11, 2003.

28 Numbers for gas demand are taken from EIA’s Natural Gas Monthly and 

consist of gas demand for July, August, September and October for the most 

recent year available, 2002.

29 American Gas Association, “The Evolution of Underground Natural Gas 

Storage: Changes in Utilization Patterns,” August 2000, saying LDCs have “ownership or contractual rights to about 73% of the total storage capacity.”

30 For example, in its press release titled “El Paso Reports First Quarter 2003 

Results,” dated May 13, 2003, El Paso reported “a substantial reduction in the 

size of the transportation and storage portfolios and their related hedges.” El 

Paso also reported that its “storage portfolio was reduced by 56 percent, from 

125 Bcf to 55 Bcf.” El Paso’s reductions were due primarily to its business difficulties and exit from active trading.

 Actions

Industry Actions

While there is little that can be done in the short 

term, the North American gas and power industries are 

attempting to counter the upward shift in natural gas 

prices and its resulting effects on power markets in the 

long term.
E N E R G Y M A R K E T A S S E S S M E N T

13

 The displacement of inefficient gas-fired generation with new, efficient gas turbines allows efficient dispatch that uses less natural gas to produce 

the same amount of electricity.

 The number of rigs drilling for natural gas in the 

United States has increased, as discussed previously, showing that supply is responding effectively 

to price signals.

 The natural gas industry has sought congressional approval to give drillers access to lands currently blocked from development, such as certain 

lands in the Rocky Mountains, Alaska, offshore 

California, Florida and the Carolinas, and has 

taken advantage of royalty relief in areas of the 

U.S. Gulf of Mexico. 

Commission Actions

The Commission has helped gas and power 

markets add necessary infrastructure and address 

issues that directly or indirectly affect the gas and 

power customers. 

 Expedited Pipeline Certificates: On average, pipeline certificates are now processed in about 200 

days at the Commission, compared to an average 

turn-around time of almost 300 days 10 years ago. 

The Commission has authorized almost 16 Bcfd 

of new pipeline capacity since January 2001. More 

than 50 percent of these additions are expected to 

serve new power plants, with the greatest growth 

in that sector in the Southeast and West.

 Further Certificate Streamlining Initiative: 

FERC’s National Environmental Policy Act PreFiling Process is designed to identify issues and 

engage stakeholders early in the certificate process 

and encourage problem solving by FERC staff, 

other agencies and landowners. The objective is to 

reduce total certificate processing time. The initiative has already produced expedited results for 

several large pipeline projects.

 FERC is expediting certificates for new Rocky 

Mountain region pipeline capacity and monitoring 

price effects of capacity changes. FERC staff have 

participated and will continue to participate in 

Wyoming Pipeline Authority proceedings regarding pipeline takeaway capacity. In addition, FERC 

is paying special attention to market developments 

in the Rockies to assure that market forces can act, 

unimpeded by inappropriate factors. 

 Monitoring and Enforcement of Markets: FERC 

staff continues to monitor natural gas and electric 

market activity to oversee the marketplace and 

identify in real time any developments that could 

harm customers or the market itself. Short- and 

long-term market developments are analyzed 

to determine whether they require Commission 

action. In April and June 2003, FERC staff held 

conferences to encourage measures to improve gas 

price reporting and index calculations, which were 

adopted in the Commission’s policy statement.31

 Revised LNG Terminal Policy: As part of FERC’s 

order preliminarily approving construction of 

the proposed Hackberry LNG terminal, the 

Commission announced that LNG facilities 

would not be classified as open-access facilities. 

Instead, these facilities are treated as natural gas 

production facilities, allowing them to charge 

market-based rates for terminal services. This will 

not affect markets in the short term, but FERC 

anticipates that this new policy will stimulate 

development of new LNG terminals by streamlining the development cycle and reducing potential 

regulatory risks. LNG has grown in importance not 

only as a source of additional gas supply for North 

America, but also due to the use of LNG facilities 

as a strategic resource to increase efficiency of the 

pipeline grid. FERC also approved the expansion 

of CMS Trunkline LNG Co.’s terminal.

 The Commission has been addressing issues 

regarding Order No. 637, which dealt with pipeline segmentation, standards and issues relating 

to capacity release. These decisions are increasing 

the efficiency of the existing assets in the pipeline system.

31 FERC, Docket No. PL03-3-000, July 25, 2003.
E N E R G Y M A R K E T A S S E S S M E N T

14 
15

E N E R G Y M A R K E T A S S E S S M E N T

A lack of demand responsiveness in electricity 

markets costs customers 

in times of peak demand. 

When prices for electricity rise, 

few customers see this change 

in time to respond and, thus, 

do not have the opportunity 

to reduce their electricity use. 

During periods of transmission 

constraints or high demand, 

these prices can rise substantially. 

Rather than reducing supply 

to those customers who would prefer to reduce 

consumption instead of paying high prices, market 

operators must generate or buy sufficient electricity 

to meet total price-insensitive demand, raising costs 

for all customers. In addition, lack of demand responsiveness increases the ability of suppliers to exert 

market power and raise prices for all customers. 

Absent demand responsiveness, electricity markets 

face higher prices during periods of high demand and 

congestion. Though small reductions 

in demand during these times could 

lower electric prices significantly, 

this option is lacking across most of 

the country. Customers need access 

to meaningful and accurate price 

information that reveals the value of 

electricity given the time and place 

of use. With this tool allowing customers to change their 

electricity usage in response to price, demand response 

could have a significant effect on electricity price levels, 

price volatility, system reliability and supplier market 

power. This is a more efficient means of meeting peak 

demand than purchasing electricity at peak prices.1 In the 

short run, the only likely meaningful effect on high and 

volatile electricity prices and supplier market power will 

result from policy leader exhortations for conservation, 

load shifting and other actions as a part of good energy 

citizenship.2

This chapter examines this challenge, discusses how 

the industry is attempting to address it and presents the 

Commission’s actions to address the challenge. 

 The Situation

Electricity prices are volatile. For example, in PJM, 

prices ranged from $0/MWh to $802/MWh in 2000.3 A 

primary reason for the volatility is that demand varies by 

season, day of the week and hour. For example, in 2002 

in New York City and Long Island, demand ranged from 

5,400 MW at 3 a.m. to 7,400 MW at 4 p.m. on a fall Sunday, 

and on a summer weekday in 2002, the area’s demand 

Challenge 2

LACK OF DEMAND

RESPONSIVENESS IN

ELECTRICITY MARKETS

Market power 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.

Volatility is a 

measurement of the 

price fluctuation of a 

commodity that takes 

place over a certain 

period of time.

1

 Severin Borenstein, “Time-Varying Retail Electricity Prices: Theory and 

Practice,” University of California Energy Institute, undated.

2

 Department of Energy, “Abraham Unveils Smart Energy Use Education 

Campaign,” press release, July 9, 2003.

3

 PJM systemwide real-time hourly prices retrieved from www.pjm.com/markets/

jsp/lmpmonthly.jsp on June 23, 2003. 
E N E R G Y M A R K E T A S S E S S M E N T

16

ranged from 8,500 MW to 15,000 MW between the same 

hours.4 Figure 2-1, which shows peak hourly demand 

in PJM, highlights the seasonality of demand — peak 

demand in the summer is more than twice as high as 

in early spring — but also shows that demand changes 

unpredictably, such as during the sharp peak in April due 

to unseasonably warm weather.

In periods of higher demand, electricity is generally 

provided with higher-cost generation, and at peak levels of 

demand, generation costs escalate substantially.

Though prices rise in large part due to higher 

demand, they may also rise due to transmission congestion, 

which can constrain delivery of electricity across transmission lines. This can occur when generation located outside 

an area is less expensive than generation within the area, but 

cannot reach load because of limited transmission capacity. 

Demand responsiveness can reduce the high cost of 

electricity during periods of high demand or congestion, 

since relatively small changes in demand can have large 

effects on price. For instance, in the illustrative schematic 

shown in Figure 2-2, a 1 percent reduction in demand lowers 

Figure 2-1: Electricity demand varies with the season, but can also vary unpredictably

Source: PJM systemwide peak hour load retrieved from www.pjm.com/pub/account/loadhryr/2002.txt on July 3, 2003.

Jan ‘02

Feb ‘02Mar ‘02

Apr ‘02

May ‘02

Jun ‘02

Jul ‘02

Aug ‘02

Sep ‘02

Oct ‘02

Nov ‘02

Dec ‘02

Figure 2-1

08-22-03

D

aily

p

e

a

k lo

a

d in

P

J

M

–

E

a

st (M

W) 60,000

50,000

40,000

30,000

20,000

10,000

0

the price by nearly 50 percent, saving all customers, not just 

those who reduced demand, more than $400/MWh. 

Because most customers are not aware of dramatic 

price changes when they occur, but see only a long-term 

average price, they cannot respond by reducing or shifting 

consumption. Incorporating demand responsiveness into 

electricity markets would lower demand at times of high 

prices, thus lowering electric prices and financially benefiting customers. It has been estimated that incorporation of 

demand response into wholesale electric markets would 

save customers $70 million in 2004, growing to $3 billion 

in 2020.5 Looking back at summer 2000, the Electric Power 

Research Institute estimated that California customers 

could have saved $700 million if peak demand had been 

2.5 percent lower.6 A study of New York’s demand response 

4

 New York Independent System Operator, “Integrated Real Time Actual Load.” 

Data for Oct. 13, 2002, and July 29, 2002, retrieved from mis.nyiso.com/public/P58Clist.htm on June 22, 2003. 

5

 FERC, “Economic Assessment of RTO Policy,” prepared by ICF, Feb. 26, 2002, 

Table ES-1, p. vi. 

6

 Steven Braithwait and Ahmad Faruqui, “The Choice Not to Buy: Energy Savings 

and Policy Alternatives for Demand Response,” Public Utilities Fortnightly, vol. 

139, no. 6, March 15, 2001, pp. 48-60, see especially table 2. 
E N E R G Y M A R K E T A S S E S S M E N T

17

Curtailable load is 

subject to interruption 

by the grid operator.

In electric markets a 

baseline refers to an 

agreed-upon level of 

electricity consumption 

from which deviations 

are measured. 

Baselines are usually 

based on a customer’s 

historical usage. The 

variation in usage from 

the baseline may be 

billed at a different rate.

Real-time pricing 

provides signals to 

customers on the 

value of consuming 

energy at the time of 

consumption.

Time-of-use pricing is 

a rate design imposing 

higher charges to 

customers during 

periods of the day when 

higher demand 

is experienced.

Figure 2-2: Small reductions in demand can lower electricity prices significantly

Source: Confidential bid data and illustrative demand curves.

participation estimates that the 

region’s customers saved up to $15 

million in 2002.7

The primary way that demand 

responsiveness is incorporated 

into electricity markets is by giving 

customers the opportunity to 

respond to price signals that reflect 

system conditions, including resource 

adequacy and local deliverability 

conditions. Variations of dynamic 

pricing, such as real-time pricing, 

time-of-use pricing (TOU), TOU rates 

with critical peak pricing (in which 

unusually high prices are charged for 

a limited number of hours) and TOU 

rates with curtailable load charge 

customers a higher rate when supply 

is expensive and a lower rate when 

supply is inexpensive. Some demand 

response tariffs pay customers to 

curtail load. For example, emergency 

demand response tariffs pay or give 

a discount to large customers for 

reducing load when called, often up 

to a specified number of hours, and 

demand bidding allows customers 

to bid demand reductions into the 

market. Some tariffs are designed 

to incorporate dynamic pricing, but 

only for deviations from established 

baselines. Tariffs with baselines are 

attractive because customers can still 

pay the same rate for their current 

usage, but the tariffs still provide an 

incentive for customers to reduce or 

shift consumption during high-priced 

periods. In addition to tariff designs, demand response 

can be achieved by automatically controlling customer 

appliances, such as by programming air conditioners 

Load (MW)

20,000 22,000 24,000 26,000 28,000 30,000 32,000

$1,000

$800

$600

$400

$200

$0

Pric

e ($/M

W

h)

P = Price

Q = Load

P =$504

Q =30,424 MW

1

1

P =$925

Q =30,637 MW

0

0

Figure 2-2

08-22-03

Decrease = $421

7

 Neenan Associates, “How and Why Customers Respond to Electricity Price 

Variability: A Study of NYISO and NYSERDA 2002 PRL Program Performance,” 

January 2003. This report was commissioned by NYISO and the New York State 

Energy Research Authority. The study did not quantify the reduction in deadweight losses due to demand response participation. Deadweight losses result 

from retail prices that fail to reflect the underlying marginal cost of supply.
E N E R G Y M A R K E T A S S E S S M E N T

18

to change temperatures at predetermined times or to 

respond to external electronic signals.

In some cases, demand reductions have been 

achieved without direct price signals but by exhorting 

customers to behave differently. During the energy crisis 

in California, for example, customers reduced peak June 

2001 consumption by 14 percent, due in part to advertising by the state that urged Californians to reduce or 

shift consumption to help the state manage through the 

energy crisis.8 Because most markets lack real-time price 

signals that reach the end-use customer, only advertising 

calling for “good energy citizenship” 

will be a driver of demand reductions this summer. The Department 

of Energy, for example, has urged 

energy conservation this summer to 

help reduce demand for natural gas, 

which is currently in tight supply.9

Demand response reduces the potential for generators to exert market power in times of scarcity, further 

Demand is inelastic

if customers do not 

change their demand in 

response to a change 

in price.

Table 2-1: Demand response participation identified in electricity markets with ISOs remains low

Maximum reduction achieved (MW)

Peak 

load 

(MW)

Demand 

response as 

percentage 

of peak

2001 2002 2002 2002

CAISO 42,441 0%

 Demand Relief 162 0

 Discretionary Load Curtailment 22 0

ISO-NE 25,348 0%

 Demand Response 1 0

 Price Response 20 18

NYISO 30,644 3%

 Emergency Demand Response 455 836

 Day Ahead Demand Response 25 14

PJM 63,762 3%

 Active Load Management 1,796 1,775

 Emergency 62 76

 Economic 6 101

Sources: California Independent System Operator: 2001 data are from David Kathan, “Demand Response in Wholesale Markets,” presentation 

at NARUC, July 30, 2002; using 2002 data provided by CAISO. ISO-NE: Michael W. Townsley, Stephen P. Waite and Cheryl C. Mattson, “ISO New 

England 2002 Demand Response Program Evaluation Final Report,” April 18, 2003, and personal communication with Henry Yoshimura of ISO-NE, 

May 9, 2003. NYISO: Neenan Associates, “How and Why Customers Respond to Electricity Price Variability: A Study of NYISO and NYSERDA 2002 

PRL Program Performance,” January 2003. PJM: “2002 Load Response Program” report to FERC, May 31, 2003.

Note: In 2001, PJM did not include PJM West.

contributing to lower prices for customers. If demand is 

inelastic, a seller can try to raise prices above competitive 

levels. However, if demand decreases in response to a 

price increase, the profitability of and incentive to exert 

supplier market power is reduced. 

Demand response will play a limited role in 

the near term, reducing the ability to lower prices 

during periods of peak demand and transmission 

congestion. Nationwide, demand response participation 

occurs in most regions, but generally participation is 

limited. This challenge continues for most markets, given 

the expectations of high gas price-driven electric prices. 

Table 2-1 details demand response participation in regions 

with independent system operators (ISOs) for 2001 and 

2002 and describes actual peak load reductions. Current 

estimates are not available. Demand response participa8

 California Energy Commission, “Reduction in 2001 Monthly Peak Demand,” 

available from www.energy.ca.gov/electricity/peak_demand/2001_peak_

demand.html.

9

 Department of Energy, “Abraham Unveils Smart Energy Use Education 

Campaign,” press release, July 9, 2003.
E N E R G Y M A R K E T A S S E S S M E N T

19

tion, as reported in Table 2-1, did not exceed 4 percent of 

peak demand in any market. 

Table 2-2 estimates demand-response potentials as a 

percentage of total demand in the North American Electric 

Reliability Council (NERC) regions for 2002 and 2003, 

which are based on best estimates for both years, not 

observed and reported reductions, and reveals that little 

identified demand response exists in each region. As seen 

by comparing Table 2-2 (above) with Table 2-1, although 

some NERC regions show higher levels of demand 

response than ISO markets, the systemwide average 

estimate of the amount of load available to respond to 

high prices is less than 4 percent of peak demand. 

Lack of demand-responsive participation can be 

attributed to a variety of factors, including the following. 

 End-use customers have to modify their electricity 

usage for demand response to occur. This requires 

retail rate structures and policies that encourage 

clearer pricing and information options for key customer groups.

 Real-time pricing can expose the geographic and 

temporal variations of prices, exposing some customers to higher prices than they had been paying. For 

example, during market redesign proceedings, some 

localities expressed concern that such real-time pricing could raise their prices because they are located 

in the San Francisco Bay Area, a constrained area 

in California. This may be true, but in the long-run 

Table 2-2: Estimates of total demand response are low in NERC regions in 2002 and 2003

2002 2003

Estimated 

peak demand 

response (MW)

Actual peak 

regional demand 

(MW)

Estimated demand 

response as share 

of peak demand

Estimated 

peak demand 

response (MW)

Projected peak 

demand (MW)

Estimated demand 

response as share 

of peak demand

ECAR 3,000 101,150 3% 3,000 97,800 3%

ERCOT 160 56,233 0% 720 56,900 1%

FRCC 2,700 40,260 7% 2,800 38,800 7%

MAAC 1,600 55,569 3% 1,300 55,000 2%

MAIN 3,300 55,300 6% 3,200 54,100 6%

MAPP 1,600 33,830 5% 1,600 33,600 5%

NPCC 1,000 105,166 1% 0 104,000 0%

SERC 6,100 157,333 4% 1,600 152,000 1%

SPP 1,500 39,571 4% 1,400 38,700 4%

WECC 1,700 136,108 1% 1,800 135,000 1%

Source: NERC, summer assessments for 2001, 2002 and 2003. ”Estimated peak demand response” is expected interruptible demand and directcontrol demand-side management. “Projected peak demand” is projected net internal demand.

these tariffs lower costs to all customers by reducing consumption of expensive electricity in areas to 

which it is hard to deliver, lowering prices for high 

cost power as well as the potential for the exercise of 

market power.10

 Emergency curtailment and demand bidding, as well 

as some dynamic pricing tariffs, require that customer 

baselines be set. These baselines are problematic 

because groups of customers will lobby for baselines 

that benefit their usage and they encourage customers to use electricity in ways that benefit their baselines.11 Furthermore, baselines may confer a right to 

electricity consumption that other stakeholders may 

oppose, and this opposition can stall development of 

demand-response tariffs. 

 Market participants often lack adequate awareness 

of demand-response opportunities or do not fully 

understand how demand-response tariffs work and 

can be financially beneficial. Retail and wholesale 

energy providers must do more to promote demandresponse participation and educate end-users.

 Many demand-response options, as currently 

designed, are complex and costly for customers to 

implement. Despite more than a decade of research, 

10 Severin Borenstein, Michael Jaske and Arthur Rosenfeld, “Dynamic Pricing, 

Advanced Metering and Demand Response in Electricity Markets,” Center for the 

Study of Energy Markets (CSEM) Working Paper 105, October 2002. 

11 Severin Borenstein, “Time-Varying Retail Electricity Prices: Theory and 

Practice,” University of California Energy Institute, undated.
E N E R G Y M A R K E T A S S E S S M E N T

20

some believe that more research is needed to determine how to make meaningful demand response or 

demand-response proxies available and easy for a 

broader range of customers. 

 Actions

Industry Actions

 Some regions are relying on demand-response participation to serve load reliably. For example, with regulatory leadership from the New York 

Public Service Commission, NYISO has 

increased demand-response participation in New York City and Long Island, 

both areas with continued reliability 

concerns. In 2002, these localities 

accounted for nearly 20 percent of the 

statewide load curtailment, compared 

to 12 percent in 2001. ISO-NE expects 

that aggressively promoted demandresponse participation will result in 

20–50 MW of reductions during peak 

hours in the southwest Connecticut 

load pocket, reductions needed to help maintain reliability in the area.12 (For comparison, the region has 

invested in emergency transmission and generation that 

is expected to provide an additional 170 MW.13)

 ISO-NE received approval from FERC to increase 

minimum payments to customers who are called on 

to curtail load.14 The increase provides a higher level of 

price certainty to customers, improving the attractiveness of participating. However, though the real-time 

price is typically higher than the minimum guaranteed 

payments, the increase could result in subsidization of 

demand response if the minimum payment is higher 

than the market price.

 To integrate the role of demand response into its market, NYISO has tied the activation of demand response 

to prices in the spot markets.15 When demand response 

resources are activated, NYISO will set the market-clearing price for energy based on the payments provided 

to the activated demand response resources and all 

resources, including supply, will receive the same price. 

In addition to improving the economic efficiency of the 

tariff, this modification helps secure ongoing support 

Load pockets are areas 

isolated by the limits 

of the transmission 

network to get power to 

them; demand within 

the load pocket exceeds 

internal generation, so 

imports are needed or 

reliability will fail.

Locational marginal 

price is the marketclearing price for 

electricity at the 

location the energy is 

delivered or received.

for the tariff from all market participants.

 PJM has expanded its demand response tariff to 

allow customers on real-time 

locational marginal pricing to 

also participate in economic 

demand response, which allows 

customers to reduce load and 

be compensated at the current 

locational marginal price. In 

addition, PJM expanded its pilot 

program that allows customers without advanced meters 

capable of recording real-time electricity use to elect 

time-varying pricing. It has expanded from customers 

with loads up to 25 MW to customers with loads of 

up to 100 MW.16

 Many regions are working to implement new demand 

response programs or improve existing ones. 

 California is currently working to implement 

two variations of demand response: real-time 

metering for industrial customers and a pilot 

time-of-use tariff for residential and small retail 

customers. Although California spent $35 million 

on 20,000 real-time meters in 2000 and 2001, 

the meters have not been used with real-time 

pricing because the California Public Utilities 

Commission has not adopted electricity rates that 

leverage the full capability of these meters.

 The California Power Authority announced the 

availability of $30 million in tax-exempt industrial development bonds that can be used to 

finance new load management equipment by 

manufacturers. 

 Gulf Power in Florida, which has a retail tariff 

that combines time-of-use with critical peak pricing, is implementing improvements. The company is installing more advanced equipment that 

is easier to use, provides more information on 

prices and total consumption and provides more 

control of current consumption.

12 Personal communication with Shiv Mani, ISO New England, June 19, 2003.

13 Stacy Wong, “Connecticut Utility Taking Steps to Avoid Blackouts, Brownouts 

This Summer,” Hartford Courant, June 10, 2003. Also, personal communication with Peter Brandien, Connecticut Light & Power, June 19, 2003.

14 FERC Docket No. ER02-2330, June 6, 2003.

15 FERC Docket No. ER03-766, June 20, 2003.

16 Susan Covino, PJM, personal communication, July 11, 2003. 
E N E R G Y M A R K E T A S S E S S M E N T

21

Commission Actions

The ability to incorporate demand responsiveness 

into electricity markets is often found at the retail level. 

Nonetheless, FERC is working to better incorporate 

demand response into wholesale electricity markets. 

 FERC is committed to market-design rules that 

allow demand resources to participate on equal 

footing with supply resources in day-ahead, realtime and capacity markets.17

 The Commission monitors electric markets to 

ensure that demand response is properly and fairly 

administered, and requires that market monitors 

report on demand-response participation in their 

annual reports.

 To encourage the development of demand 

response, in 2003 the Commission approved 

changes to the rates of ISO-NE, NYISO and PJM. 

These changes should increase customer participation in demand response, allocate costs more 

equitably and allow easier access to markets for 

aggregators of demand response.18

 FERC has proposed standard interconnection rules 

for small generation. The intention is to make it 

less difficult for distributed generation to participate in the market.19

 The Commission is working with the U.S. 

Department of Energy on analysis of distributed 

generation resources and their effect on electricity 

markets, including costs, price and reliability. 

 As a participant in the New England Demand 

Response Initiative, FERC is working to develop 

better market rules and demand response for 

ISO-NE.

Day-ahead markets

are 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.

Real-time markets

are electric markets 

that settle — or, 

determine the price 

— for one-hour periods 

or less during the day 

of delivery.

Capacity markets exist 

to ensure that power 

is available when it 

is needed; a capacity 

market requires 

companies with an 

obligation to deliver 

electricity to customers 

to pay power plant 

owners for having their 

units up and running 

and able to produce 

additional energy.

17 FERC White Paper, “Wholesale Power Market Platform,” April 28, 2003.

18 FERC Docket No. ER03-303, March 21, 2003, and Docket No. ER03-810, June 

25, 2003.

19 FERC Dockets No. RM02-1-000 and RM02-12-000, July 24, 2003.
E N E R G Y M A R K E T A S S E S S M E N T

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23

E N E R G Y M A R K E T A S S E S S M E N T

Challenge 3

FINANCIAL STRESS

OF SOME NATURAL

GAS AND ELECTRIC

MARKET SECTORS

S

ince 2001, large sectors 

of natural gas and 

electric markets have 

experienced a financial 

crisis accompanied by a loss of 

investor confidence, a dramatic 

decline in financial liquidity 

and project delays and cancellations. These problems have 

adversely affected customers by 

reducing the number of companies active in energy markets, 

consequently limiting market 

liquidity and effectiveness.

In the first half of 2003, 

while a few companies filed for 

bankruptcy, many companies 

in the beginning of the year 

negotiated debt-refinancing deals 

that allowed them additional time to implement 

revised business strategies and await improving 

market conditions. If financial conditions continue 

to improve, the industry can move into a new phase 

characterized by streamlined costs, a refocus on core 

business lines, continued improvements to balance 

sheets and, in some cases, a change in ownership, 

management and business strategies. The results 

should improve market liquidity over the longer 

term, making markets more efficient and giving 

customers choices.

Although the industry is still recovering from 

the loss of market capitalization incurred since 2001, it 

appears to have reached a new, reduced-value plateau 

that could be the starting point for future growth. For 

the FERC Energy Market Participant Index of more than 

90 companies (see Appendix D) as of June 20, year-todate market capitalization was up almost $34 billion, 

or 11 percent, compared to a loss of $91 billion, or 29 

percent, in 2002.

Because financial uncertainty continues, however, the 

industry and its customers must 

contend with shrinking physical 

and financial energy markets due 

to participants that have exited or 

scaled back trading. This contraction gives customers fewer choices 

and reduces market efficiency. 

Financial troubles can be accompanied by reduced 

capital expenditures and consequent operational 

difficulties. Finally, financial stress creates the incentive for potentially inappropriate interaffiliate cash 

management practices because the costs could be 

inappropriately borne by customers of regulated affiliates.

This chapter examines these issues, discusses 

how the industry continues to evolve in response 

to them and presents the Commission’s actions to 

address the issues. 

Financial liquidity

generally describes 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.

Market liquidity

describes the ease with 

which a buyer can buy 

or a seller can sell at 

a prevailing price in a 

marketplace.

Market capitalization 

measures company 

market value and is 

computed as stock 

market price per share 

of stock times the 

total number of shares 

outstanding.
E N E R G Y M A R K E T A S S E S S M E N T

24

 The Situation

The acute financial stress experienced by natural 

gas and electric market participants that began in 2001 

and 2002 has eased somewhat. Although the industry has 

not recovered from the severe loss of market capitalization incurred since 2001, it appears to have reached a 

new, reduced-value plateau that could be the starting 

point for future growth. For the FERC Energy Market 

Participant Index of more than 90 companies,1 Figure 3-1 

demonstrates that as of June 20, 2003, year-to-date market 

capitalization was up almost $34 billion (11 percent), 

compared to a loss of $91 billion (29 percent), in 2002.

Many companies that continue to be weak 

financially have exposure to either unregulated power 

generation or wholesale trading. These companies remain 

particularly troubled due to weak fundamentals that 

continue to cloud performance. Some characteristics 

of unregulated power generation or wholesale trading 

sectors include: 

 regulatory uncertainty,

 excess power supplies and depressed forward 

electricity price curves,

 limited access to equity markets,

 poor market liquidity, and

 bad credit profiles.

At the beginning of 2003, there was widespread 

speculation that the industry could expect a number 

Figure 3-1: Market capitalization of FERC Energy Market Participant Index companies increased in 2003

$0

$100

$200

$300

$400

$500

Jan ‘99 Jan ‘00 Jan ‘01 Jan ’02 Jan ‘03 6/20/03

Market Capitalization

($ Billions)

Figure 3-1

08-22-03

Source: Bloomberg financial data applied to FERC Energy Market Participant Index.

A forward price curve is 

the chronological set of 

prices determined by a 

market for a good that 

will be delivered in the 

future.

of bankruptcies because some companies with limited 

access to equity markets confronted 

short- and long-term debt maturities. 

Though some companies have filed 

for bankruptcy this year,2 by the end 

of July, more than 90 percent of the 

debt and credit maturing in 2003 

judged by OMOI to be stressed,3 had 

been successfully refinanced. Banks 

appear willing to avoid writing off 

bad loans, exercise patience and allow for balance sheet 

and operational restructuring instead of forcing bankruptcies. Even companies with significant unregulated business 

operations such as Dynegy, Reliant Resources and Aquila 

have succeeded in refinancing both short- and long-term 

debt since the beginning of 2003. These recent refinancing 

deals may simply delay serious debt and financial liquidity 

issues into 2004 and beyond. 

1

 FERC has developed an Energy Market Participant Index by combining multiple 

industry lists. The index includes electric distributors, electric generators, utility 

parent companies, integrated electric companies, gas distributors and midstream 

gas companies. See Appendix D for the list of companies.

2

 NRG Energy Inc., which filed for bankruptcy on May 14, 2003, “NRG Energy, 

Inc. Files Voluntary Chapter 11 Petition To Implement Negotiated Restructuring 

Plan,” press release, May 14, 2003; PG&E National Energy Group, which filed for 

bankruptcy on July 8, 2003, “PG&E National Energy Group Inc. To Reorganize 

Under Chapter 11 Protection,” press release, July 8, 2003; Mirant Corp., which 

filed for bankruptcy on July 14, 2003, “Mirant Files Chapter 11 Petitions to 

Facilitate Financial Restructuring,” press release, July 14, 2003. 

3

 In January 2003, OMOI identified approximately $40 billion of debt and credit 

maturing in 2003 held by 15 stressed companies. Companies that were determined to be stressed and most at risk for default and renewal failure had large 

quantities of debt maturing in 2003, held credit ratings of BBB or lower with a 

negative outlook and had not already had a default occur (since OMOI was trying to predict defaults that had not already happened).
E N E R G Y M A R K E T A S S E S S M E N T

25

Financial stress has forced market participants to exit trading, reducing the liquidity of 

physical and financial energy markets and the 

ability of participants to provide services to the 

market that improve efficiency. Companies such 

as Reliant, El Paso and Williams have recently exited 

speculative trading or announced plans to do so.4

Other market participants that continue to trade 

are limited by their weak financial conditions. In 

addition, continuing investigations regarding past 

trading practices are limiting trading. Uncertainty is 

causing companies to behave more conservatively, 

expressing concern about whether their current 

strategies and actions, especially in trading, may be 

viewed later as manipulative or abusive.

Trading is a necessary 

extension of competitive physical 

energy delivery because it increases 

market liquidity. Market liquidity is important because it gives 

buyers and sellers a number of 

parties with whom to do business 

and helps establish price levels 

through competitive bidding. 

Figure 3-2

08-22-03

Share of energy companies that are noninvestment grade

Share of energy companies that are investment grade

100%

80%

60%

40%

20%

0%

Jan ‘00 Jan ‘01 Jan ‘02 Jan ‘03 3/31/03

Bid-ask differential is 

the difference in price 

between what a buyer 

offers to pay for a 

commodity and what a 

seller offers to accept 

for a commodity.

Figure 3-2: The number of noninvestment grade U.S. gas and electric companies 

has increased since 2002

Source: OMOI analysis of U.S. natural gas and electric companies rated by Standard and Poor’s.

Having fewer trading participants reduces market 

liquidity, particularly at less active trading points. A 

lack of trading partners can lead to higher bid-ask 

differentials, increase price volatility and increase prices 

for wholesale and retail customers. When many suppliers compete at trading points, they offer choices to the 

market that can lower prices for customers. 

Reduced market liquidity also can lead to reduced 

transparency in energy markets. A key product of any 

efficient market is accurate information about the 

prevailing price in that market. Having fewer traders 

completing transactions means fewer market participants reporting price information to the marketplace 

through price indices. Price information helps customers determine the cost of meeting their needs, helps 

sellers determine the value of their investment and, 

when the system works correctly, efficiently allocates 

resources to the customers who most value them. The 

quality of price indices depends in part on the number 

of active participants trading at a given price point.

Financial stress continues for market 

participants, potentially hampering operations. 

Debt levels remain high and the electric and natural 

gas sectors continue to experience credit rating downgrades and poor financial liquidity. Credit-rating 

downgrades continued through the first quarter of 

2003. Figure 3-2 shows that the percentage of gas and 

electric companies rated as noninvestment grade by 

Standard and Poor’s has increased since 2002. 

4

 Reliant Resources Inc., “Reliant Resources exits proprietary trading,” press 

release, March 7, 2003; El Paso Corp., “El Paso Corporation Announces Third 

Quarter 2002 Results and Plan to Exit the Energy Trading Business,” press 

release, Nov. 8, 2002; The Williams Cos. Inc., “Williams Reports Third-Quarter 

Net Loss of $294.1 Million,” press release, Nov. 14, 2002, and 2002 Annual 

Report, March 19, 2003.
E N E R G Y M A R K E T A S S E S S M E N T

26

Creditworthiness can also affect contracts. For 

example, NRG recently attempted to terminate a 

contract with Connecticut Light and Power Co. (CL&P) 

to provide power in the constrained southwest area of 

Connecticut, citing its bankruptcy as the reason.6

Financial stress reduces capital expenditures. 

Power generation is adequate across most of the country. 

However, financial stress may lead some companies to 

postpone or cancel planned generation or transmission 

infrastructure projects. As shown in Figure 3-3, capital 

expenditures declined by 10 percent in 2002 for companies within the FERC Energy Market Participant Index. 

While integrated electric companies and electric distributors continued to have increased capital expenditures, 

most sectors, particularly those with wholesale exposure, 

reduced their capital expenditures.

Noninvestment grade credit 

levels can hamper business functions. 

For example, generators without a 

specified creditworthiness may have 

to prepay or establish 100 percent 

collateral for fuel,5 deal with a limited 

number of suppliers or have difficulty meeting New York Mercantile 

Exchange (Nymex) margin requirements, which have increased with 

higher gas costs. Scheduled power 

sales may be hampered if electric grid 

independent system operators (ISOs) 

or regional transmission organizations 

(RTOs) tighten credit requirements 

for market participation. Defaults on 

project-financed generation could 

result in banks ultimately owning and operating power 

plants, but banks have shown little inclination to take over 

generation assets so far.

Margin requirement is 

the amount of money 

required to hold futures 

contracts and cover 

changes in the value of 

futures contracts.

Project financing is a 

form of asset-based 

financing in which a 

firm finances a discrete 

set of assets (the 

project) on a standalone basis.

Figure 3-3: Year-to-year change in capital expenditures

shows decline in 2002 expenditures 

Source: Bloomberg data applied to FERC Energy Market Participant Index.

5

 Collateral may be provided through prepayment, a letter of credit or, if possible, a guarantee from a parent company.

6

 Reuters, “Bankrupt NRG halts further power sales to CL&P,” June 13, 2003.

Electric

Distributors

Electric

Generators

Utility Parent

Companies

with

Significant

Wholesale

Exposure

Utility Parent

Companies

with

Minimal

Wholesale

Exposure

Integrated

Electric

Gas

Distributors

Mid-stream

Gas

FERC Energy

Market Participant Index

figure 3-3

08-22-03

32%

10%

67%

-27%

43%

-14%

23%

0%

20%

7% 6%

-1%

26%

-10%

36%

-10%

Year-to-Year Change in Capital E

x

penditures (%) 80%

60%

40%

20%

0%

-20%

-40%

2001 compared to 2000

2002 compared to 2001

4.7 8.5 28.5 6.9 10.3 3.7 6.7 69.2

2002 Capital Expenditures (Billions of $)
E N E R G Y M A R K E T A S S E S S M E N T

27

Co., both entities have the same rating due to close 

financial ties and a lack of effective ring-fencing.10

If regulated utilities purchase generation plants 

or other assets, those acquired assets may be put into 

regulated rate bases. Regulatory oversight should 

ensure that subsequent regulated revenue requirements are based on the lesser of cost or market value 

to protect regulated customers.

 Actions

Industry Actions

With the goals of enhancing shareholder value, 

regaining investor confidence and reducing cost and 

collateral requirements, some companies have revised 

their strategies and business models in fundamental ways 

to include: 

 refocusing on core competencies and domestic 

markets;

 re-emphasizing regulated assetbased business plans and opportunities rather than unregulated 

power generation and revenue 

growth via trading;

 reducing exposure to counterparties that are not creditworthy, 

reducing trading limits, seeking 

collateral and moving towards 

credit clearing;

 scaling back trading operations 

from market-making and speculative activity to assetbased trading, or abandoning trading altogether; and

 selling assets to strengthen balance sheets.

Companies with wholesale exposure were, until 

recently, involved in most infrastructure development projects and were willing to engage in higher 

risk growth strategies targeting competitive markets. 

Smith Barney Citigroup estimated in May that more 

than 16,000 MW of new generation had been either 

delayed or cancelled since February 2002.7

Financial stress increases the need to 

ensure that the problems of nonregulated affiliates do not harm regulated utility customers. 

With nonutility businesses performing poorly, there 

may be pressure to raise funds and a greater temptation for unregulated parent companies to use the 

financial resources of regulated affiliates to shore up 

finances than would be the case under more favorable conditions. For instance, businesses may seek 

to pledge regulated assets as collateral for unregulated businesses. If this occurs, rates to customers 

could increase if unregulated businesses default on 

commitments and regulated companies have to pay 

off the loans or if the cost of capital were to increase 

for the utility.

Ring-fencing techniques help isolate affiliate 

credit risk, protecting regulated assets from risks 

such as those presented during the Enron bankruptcy.8

 Ring-fencing mechanisms include regulatory 

restrictions, both state and federal, financial 

constraints and organizational structure. The quality 

and strength of a ring-fence contributes to the 

differential in credit ratings between a regulated 

entity such as a utility or interstate pipeline and its 

corporate parent; the cost of funds to a regulated 

entity may be substantially lower if the ring-fencing 

is perceived by lenders or investors to be effective. Typically, 

a regulated utility will have a 

credit rating somewhat superior 

to a utility holding company. For 

example, the Portland General 

Electric Co. subsidiary maintains 

its own investment grade credit 

fully independent of Enron due 

to effective ring-fencing techniques required by 

the Oregon Public Utility Commission, including 

structural mechanisms and regulatory insulation at 

the state level.9 In some instances, however, such as 

that involving Dynegy and subsidiary Illinois Power 

Ring-fencing refers 

to techniques used to 

isolate the credit risk 

of a subsidiary within 

a corporation from the 

risk of its affiliated 

companies.

Credit clearing is a 

mechanism for settling 

mutual claims, the 

result of which is that 

the risk that a specific 

company might fail to 

fulfill its contract is 

substantially reduced by 

pooling among 

many companies.

7

 Smith Barney Citigroup, Weekly Energy Wire, May 8, 2003, p. 8. 8

 As an example, prior to the Enron bankruptcy, two Enron pipeline subsidiaries 

pledged assets as collateral for loans and passed the funds to Enron just before 

its collapse. More recently, there has been concern at the state and federal levels 

with planned issuances by Aquila and Westar of debt collateralized by regulated 

assets.

9

 Standard and Poor’s, “An Enron Subsidiary is Ring-Fenced,” Jan. 16, 2003.

10 Fitch Ratings, “Rating Linkage Within U.S. Utility Groups: Ring Fencing 

Mechanisms,” April 8, 2003.
E N E R G Y M A R K E T A S S E S S M E N T

28

Other important developments include:

 nontraditional marketing entities such as financial institutions and producer-affiliated companies entering or expanding energy trading;11

 industry group initiatives such as the recommended best practices of the Committee of Chief 

Risk Officers (CCRO) to restore confidence in 

trading and the development of master trading 

agreements;12

 clearing services from the New York Mercantile 

Exchange (Nymex), IntercontinentalExchange 

(ICE) and EnergyClear, and other approaches 

such as insurance by Virtual Markets Assurance 

Corp. to reduce collateral requirements, improving market liquidity; and

 active participation in the debate for industry 

recovery from ratings agencies, bond insurance 

companies and fixed-income investors, many of 

which have become increasingly vocal about the 

need to protect regulated assets from bankrupt 

and distressed corporate holding companies with 

tools such as ring-fencing. 

Commission Actions

FERC has taken action or proposes to take action on 

these financial challenges to:

 Enhance policy under Section 204 of the Federal 

Power Act. The Westar Order13 provides additional 

restrictions on the use of borrowed money to finance 

nonutility business. The following restrictions 

will apply to all future issuances of debt to be 

approved by the Commission: 

 debt secured by utility assets must only be 

used for utility purposes;

 if assets securing debt are divested, the corresponding secured debt must be divested or 

spun off as well; and

 if unsecured assets (utility and nonutility) are 

divested, the corresponding unsecured debt 

must be divested or spun off.

 Continue oversight of credit standards that pipelines impose on gas transmission customers to 

ensure reasonableness for all market participants.14

 Continue review of credit standards that electric 

transmission owners impose on electric generators 

and other transmission customers to ensure reasonableness for all market participants.15

 Propose expanding quarterly financial report 

forms to collect financial information from jurisdictional entities more frequently than current 

reporting requirements.16

 Regulate cash management practices to prevent 

abuses that could adversely affect the health of regulated entities and their ability to provide service.17

 Implement a wholesale power market platform 

intended to increase electricity transmission investment.18 Open transmission access will, in the long run, 

improve market liquidity. Customers will also benefit 

from fair access to transmission and broader markets.

 Set guidelines for reporting and developing price 

indices for natural gas and electricity transactions 

to help restore confidence in the current system.19

11 Reuters, “Banks Step in to Fill Trading Void Left by Enron,” April 29, 2003; 

Power Markets Week, “Thanks, But No Thanks: AEP, Most Other Leaders in 2002 

Power Sales Pulling Back,” April 28, 2003.

12 Several entities, including Edison Electric Institute (EEI), National Energy 

Marketers Association (NEM), North American Energy Standards Board (NAESB) 

and International Swaps and Derivatives Association (ISDA) have developed master trading and netting agreements.

13 FERC 102 ¶ 61,186 Westar Energy Inc., Docket Number ES02-51-000, 

Feb. 21, 2003.

14 Including Docket Nos. GT02-35-004 (Tennessee Gas Pipeline Co.), GT02-

38-005 (Northern Natural Gas Co.), RP02-363-005 (North Baja Pipeline LLC), 

RP03-7-001 (Natural Gas Pipeline Co. of America), RP03-41-003 (e prime Inc. v. 

PG&E Gas Transmission, Northwest Corp.), RP03-64-000 (Gulf South Pipeline 

Co. LP), RP03-70-001 (PG&E Gas Transmission, Northwest Corp.), RP03-162-000 

(Trailblazer Pipeline Co.), RP03-256-000 (Honeoye Storage Corp.), RP03-312-000 

(Calpine Energy Services LP v. Southern Natural Gas Co.) and RP03-354-000 

(CenterPoint Energy-Mississippi River Transmission Corp.).

15 Including Docket Nos. ER03-540-002 (Carolina Power & Light Co. and Florida 

Power Corp.), ER03-548-000 (San Diego Gas & Electric Co.), ER03-552-000 (New 

York Independent System Operator) and ER03-645-000 (Duquesne Light Co.).

16 FERC 103 ¶ 61,352 Quarterly Financial Reporting and Revisions to the Annual 

Reports, Docket Number RM03-8-000, June 26, 2003.

17 Regulation of Cash Management Practices Interim Rule, FERC, Docket No. 

RM02-14, passed June 25, 2003.

18 FERC White Paper, “Wholesale Power Market Platform,” April 28, 2003, Docket 

No. RM01-12-000.

19 FERC Docket No. PL03-3-000, July 24, 2003.
E N E R G Y M A R K E T A S S E S S M E N T

29

 Promote discussion of financial health and market liquidity concerns among all stakeholders. As 

examples, the Commission recently sponsored 

conferences on:

 capital availability and its implications for 

infrastructure investment and trading; 

 credit clearing, which has the potential to 

substantially reduce capital tied up for credit 

coverage; and

 price indices, a keystone of competitive 

markets.

 Continue work to bring closure as quickly as possible to the remaining investigations of gaming 

and withholding in western markets in 2000 and 

2001 to reduce uncertainty faced by market participants and the financial markets upon which they 

depend.

 Improve monitoring of financial health through 

greater coordination of the Commission’s audit 

functions. 
E N E R G Y M A R K E T A S S E S S M E N T

30 
31

E N E R G Y M A R K E T A S S E S S M E N T

H

igh reserve margins across much of the 

country continue. Market participants have 

taken steps toward transparent market 

designs and trading platforms as open 

and competitive energy markets evolve. Concerns 

about the quality of natural gas price reporting 

have been met with actions by industry to improve 

all energy price indices. Despite recent financial 

developments, energy markets appear to be on the 

rebound from adverse financial conditions and are 

showing signs of renewal. Market participants have 

stabilized financially while others have even seen 

modest growth. 

Though progress has been made, there are national 

challenges that markets face, including:

 High natural gas prices 

 Lack of demand responsiveness in electricity markets

 Financial stress of some natural gas and electric 

market sectors

OMOI considers the issues facing the effective 

competitive functioning of the industry to be manageable. 

To meet these challenges, however, both industry participants and regulators must seek and aggressively promote 

solutions to assure efficient, cost-effective and reliable 

electric and natural gas service to all U.S. customers. Such 

actions can address these challenges successfully and can 

maintain the benefits of a competitive electric industry for 

customers and the overall economy.

The Commission seeks to promote fair, efficient markets 

through a clear focus on its strategic initiatives to: 

 assure sufficient infrastructure;

 create balanced market rules; and

 maintain vigilant oversight and enforcement.

CONCLUSION
E N E R G Y M A R K E T A S S E S S M E N T

32