ES-1

2006

State of the Markets Report

www.ferc.gov/oversight

FEDERAL ENERGY REGULATORY COMMISSION

In 2005 and 2006, electric 

and natural gas markets in 

the United States proved 

suffi ciently robust to 

successfully meet various 

supply- and demand-related 

challenges with no major 

failures of service. 

While these markets 

continued to produce 

evidence of long-term 

developmental trends, the 

most striking forces affecting 

these markets since late 

2005 were short-term:

2006 State of the Markets Report

Executive Summary

• Hurricanes Katrina and Rita severely disrupted natural gas 

supplies in fall 2005, with resulting high prices.

• Generally mild weather – including the warmest U.S. January on 

record – resulted in a temporary glut of natural gas in the latter 

half of 2006, just one year after the hurricanes. 

• Signifi cant heat waves drove new peak electric loads in summer 

2006, with brief increases in price.

• Two large hedge funds active in energy speculation failed as 

natural gas prices sagged from immediate post-hurricane levels.

The longer term trends over this period tended to elaborate on the 

trends identifi ed previously by the Commission’s market oversight 

staff:1

• Market responses to several incidents showed the continuing 

need for investment in domestic infrastructure in some regions.

• Electric generation increased its reliance on natural gas, with 

important implications for both industries.

• Supply and demand for liquefi ed natural gas (LNG) continued 

its global expansion, with important effects on U.S. energy 

markets. 

• Futures and fi nancial markets for energy commodities continued 

their rapid growth and integrated more tightly with cash physical 

markets, accompanied by increased concerns about possible 

effects of speculation. 

Continued evolution of these energy markets in the face of shortterm supply and demand disruptions provided challenges to market 

oversight efforts, and shows no prospect of slowing.

1. Comprehensive access to Commission staff work on market oversight is available at: www.ferc.gov/oversight.
ES-2

2006

State of the Markets Report

www.ferc.gov/oversight

FEDERAL ENERGY REGULATORY COMMISSION

Natural Gas: Extreme Weather Ends 

in Supply Abundance

Late in 2005, hurricanes Katrina and Rita infl icted 

unprecedented natural gas supply disruptions on 

the United States (see Figure ES-1). At the worst 

point, immediately after Hurricane Rita, domestic 

U.S. production dropped by more than 20 percent. 

At the time, however, U.S. natural gas storage was 

relatively full and injections continued in the face of 

disruptions to demand as well as supply. 

Short-Term Issues

The sharp price increases that resulted from the 

hurricanes were most severe in the eastern United 

States, which is more directly connected to the 

damaged Gulf Coast production facilities than other 

areas of the country. When the winter turned out to be 

unusually mild, the initially high storage inventories 

remained higher than historical averages into summer 

2006, pushing prices down throughout the year. By 

fall 2006, storage had reached near-record levels, and 

LNG cargoes waited offshore in anticipation of higher 

winter prices, an unprecedented form of “offshore 

storage” that dissipated only in December.2

2. The U.S. Waterborne LNG Report, 2006 issues: Sept. 6; Oct. 5, 18, and 31; Nov. 10, 16, and 29; Dec. 7, 14, and 20. 

2005

2006

2006 Prices

2005 Prices

Hurricane Rita

Hurricane Katrina 

Hurricane Dennis 

2006 Prices at Henry Hub

2005 Prices at Henry Hub

2005 2006

0

10

20

30

40

50

60

Bcfd

$0

$2

$4

$6

$8

$10

$12

$14

$16

$18

$20

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

Price ( $/MMBtu)

Figure ES-1 U.S. Natural Gas Prices and Production Levels, 2005-06

Derived from Platts and Bentek Energy Supply/Demand Balance data.
ES-3

2006

State of the Markets Report

www.ferc.gov/oversight

FEDERAL ENERGY REGULATORY COMMISSION

Electric Power: Heat Waves, Record 

Loads, Signifi cant Demand Response

The U.S. electric power industry faced a series of 

severe heat waves that affected almost every region 

during summer 2006. Most regions set peak load 

records, in some cases as much as 10% above previous 

records (see Table ES-1). The electric industry met 

these record loads with no major wholesale outages. 

Reductions in demand for power from the grid by 

customers because of the stress of the heat waves seem 

to have proved important in preventing blackouts, 

particularly in areas that perennially face the threat of 

capacity shortages, including Connecticut and Long 

Island. These varied programs and efforts, known 

as demand response, tend to be poorly coordinated 

with short-term price signals from electricity markets 

but provided important relief to several electricity 

systems during the stresses of the summer 2006 heat 

waves. 

The larger weather pattern in 2006 was warmer 

than normal, and despite the new peaks, overall U.S. 

generation output fell a slight 0.1 percent in 2006.3

 

Financial Markets: Speculative Activity 

and Energy Markets

Continuing growth in fi nancial trading of energy 

commodities in 2006 raised concerns about the 

possible effects of speculation on physical energy 

prices. 

Speculation is the buying or selling of an interest 

in a commodity in the hope of profi ting from future 

changes in the value of that commodity. Speculation 

is a necessary part of active markets, as is participation 

by buyers and sellers of the physical commodity. 

Robust markets rely on a variety of perspectives 

about current and future market conditions to reach 

workably competitive levels.

Several reports argued that speculators increased 

North American natural gas prices in 2006.4 In 

addition, the drop in natural gas prices in mid-2006 

led to the collapse of two major speculators. The 

most notable of these was Amaranth Advisors LLC, 

which collapsed in September, apparently losing the 

most money ever by a hedge fund.5

 A smaller fund, 

MotherRock L.P., failed at the end of July, wiping 

itself out as well as losing an additional $60-$100 

million for its broker.6

 

Peak Loads

CAISO 45.4 50.3 10.7% July 24

ERCOT 60.3 62.3 3.3% August 17

SPP 40.5 42.2 4.2% July 19

MISO 112.2 116.3 3.7% July 31

PJM 133.8 144.6 8.1% August 2

NYISO 32.1 33.9 5.6% August 2

ISO-NE 26.9 28.1 4.5% August 2

Table ES-1

New RTO Record Loads Set, 2006

RTO Pre-06 2006 Increase 2006 Peak

 (GW) (GW) % Date

Source: Derived from RTO data, using hourly integrated peak loads.

3. Derived from Edison Electric Institute (EEI), Weekly Electric Output data.

4. Mark N. Cooper, for the Midwest Attorneys General Natural Gas Working Group (Illinois, Iowa, Missouri, Wisconsin), The Role of Supply, Demand, and 

Financial Commodity Markets in the Natural Gas Price Spiral, March 2006; U.S. Senate Permanent Subcommittee on Investigations, Committee on 

Homeland Security and Governmental Affairs, The Role of Market Speculation in Rising Oil and Gas Prices: A Need to Put the Cop Back on the Beat,

(Washington, D.C., June 27, 2006); Robert J. Shapiro and Nam D. Pham, An Analysis of Spot and Futures Prices for Natural Gas: The Roles of Economic 

Fundamentals, Market Structure, Speculation, and Manipulation, August 2006. Work conducted by Sonecon LLC and supported by a grant from the

National Legal and Policy Center.

5. “A Hedge Fund’s Loss Rattles Nerves,” Sept. 19, 2006, “Hedge Fund Shifts To Salvage Mode; Amaranth Trying to Shed Gas Portfolio,” Sept. 20, 2006, by Gretchen 

Morgenson and Jenny Anderson, The New York Times; “Blue Flameout: How Giant Bets on Natural Gas Sank Brash Hedge-Fund Trader,” Ann Davis, Sept. 19,

2006, The Wall Street Journal; “Amaranth - How to Lose $5.0 Billion without Even Trying,” By Cal Payne, Sept. 25, 2006, IssueAlert@UtiliPoint.com.

6. “MotherRock Cries Uncle,” thestreet.com , Aug. 3, 2006; “Energy Hedge Fund Closes Shop,” CNNMoney.com, Aug. 4, 2006.

Derived from RTO data, using hourly integrated peak loads.
ES-4

2006

State of the Markets Report

www.ferc.gov/oversight

FEDERAL ENERGY REGULATORY COMMISSION

Infrastructure: a Continuing Need 

for Investment

Natural gas and electric power markets signal 

infrastructure needs by raising prices where 

the balance of supply and demand is tight. The 

difference in prices between these locations and 

others is known as congestion. Examples of how 

transportation infrastructure can affect congestion 

include:

• Coal. Two train derailments in southern Wyoming 

reduced shipments of Powder River Basin coal 

in May 2005, drove down electric generator 

stockpiles, and changed the generation supply 

mix in some places.

• Natural Gas and Hurricane Damage. When 

hurricanes Katrina and Rita damaged gas 

production and transportation in the Gulf of 

Mexico, gas prices increased in the East, which 

attracted more gas from Texas, fi lled pipelines 

heading east, and led to persistently large East/

West price differences.

• Access to Gas Supplies in the Rocky Mountains.

As a result of tight pipeline capacity to export 

natural gas from western Wyoming, fi ve times 

in the fall of 2006 relatively minor changes in 

pipeline infrastructure led to signifi cant price 

changes.

• Electric Prices in New York City and on Long 

Island. Several new power plants in New York 

City reduced traditional transmission constraints 

into the city, dropping prices relative to stillconstrained Long Island. 

Natural gas and electric power markets remain 

Long-Term Issues

sensitive to infrastructure shortages, underscoring 

the importance of investment in transportation and 

transmission infrastructure before serious problems 

can arise.

Growing Reliance on Natural Gas for 

Electric Generation

Though U.S. electric power generation dropped 

slightly in 2006, power generators used 19.2 Bcf 

of natural gas per day through November 2006, up 

6.2 percent from 2005.7

 Gas use on the peak day in 

2006 was estimated to be 31 percent greater than 

on the peak day in 2005, peaking at roughly 42 Bcf 

on August 2 (see Figure ES-2).8

Natural gas use in electric generation increased for 

several reasons. Much more natural gas generating 

capacity was added over the past few years, even 

as plants using other fuels retired. In addition, 

natural gas traded at prices lower than competing 

fuel oil products in some markets, resulting in a 

shift in fuel use to natural gas. 

Electric power prices are increasingly infl uenced 

by natural gas prices. Though natural gas accounts 

for only about 20 percent of the power generated 

in the country,9

 it is often the fuel used by the 

plants that are the fi rst to be turned off or on and 

consequently the ones that set the price for power 

in a region. 

For natural gas, electric generation load has largely 

substituted for traditional industrial load that was 

lost as natural gas prices rose at the beginning of 

the decade. Generation load tends to be infl exible, 

resulting in additional volatility in natural gas 

prices. 

7. EIA, Monthly Flash Estimates of Electric Power Data, “Table 5.1 Trends in Fossil Fuel Consumption For Electric Generation, Total (All Sectors),” Jan. 19, 2007.

8. According to Bentek Energy LLC’s U.S. Power – Gas Burn Report. The peak day in 2005 was Aug. 3.

9. EIA, Electric Power Annual 2005 and Electric Power Monthly, January 2007.
ES-5

2006

State of the Markets Report

www.ferc.gov/oversight

FEDERAL ENERGY REGULATORY COMMISSION

Evolving Global LNG Market

Because of short-term market drivers, LNG imports 

into the United States actually declined in both 2005 

and 2006.10 Over the long term, however, imports 

are expected to grow as natural gas production in 

North America becomes increasingly diffi cult and 

expensive. LNG import projects continue to move 

forward in the Gulf of Mexico as well as on the East 

and West coasts and in Mexico and Canada.

In prior years, we observed a growing North Atlantic 

spot market for LNG that could fl ow either to North 

America or to Europe. In 2006, the LNG market in the 

Atlantic and Mediterranean basins expanded to send 

tankers as far away as Asia. 

Futures and Financial Markets Continue 

to Grow in Size and Infl uence

Futures and fi nancial trading in energy commodities 

including natural gas and electricity continued 

to increase in 2005 and 2006.11 Indicators from 

transparent parts of these energy markets show that 

participants developed new products to trade, traded 

greater volumes, and showed a greater willingness to 

hold on to sales or purchase commitments (measured 

as open interest, see Figure ES-3). Futures and 

fi nancial trading was particularly apparent in natural 

gas, but trading in electricity increased as well. 

2005

2006

MMBtu per Day

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

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

Figure ES-2 Estimated Natural Gas 

Delivered to U.S. Power Plants, 2005-06

10. EIA, U.S. Natural Gas Imports by Country, and The U.S. Waterborne LNG Report.

11. Nymex futures is a physical market in that the commitments traded provide for physical delivery and are occasionally used for that purpose. More generally,

however, traders sell (or buy) their futures commitments before settlement, allowing for participants without physical interests to participate. Consequently,

we will treat futures and fi nancial markets together because of their interactions with cash physical markets, notwithstanding the very real differences

between futures and fi nancial trading.

Year 6

Year 5

Year 4

Year 3

Year 2

12

11

10

9

8

7

6

5

4

3

2

1 Month

Open Interest (thousands of contracts) 

Source: Derived from Nymex data. 

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006

0

200

400

600

800

1,000

Figure ES-3 Natural Gas Open Interest Growth, 1997-2006

Source: Derived from Bentek Energy, Supply/Demand Balance data. Derived from Platts and Bentek Energy Supply/Demand Balance data.

Derived from Nymex data.
ES-6

2006

State of the Markets Report

www.ferc.gov/oversight

FEDERAL ENERGY REGULATORY COMMISSION

Futures and fi nancially traded natural gas markets 

interact with other commodity trading. For example, 

some interest in trading natural gas comes from 

speculators, and some from those, like pension funds, 

that have little interest in energy in its own right but 

want changing value for natural gas (and other basic 

commodities) as part of a balanced portfolio that 

includes many other investments. 

Futures and fi nancial trading also interacts with 

various physical natural gas markets. Observers tend 

to think of futures and fi nancial energy commodity 

trading as derivative of an underlying physical 

market, with futures and fi nancial trading refl ecting 

both speculation and short-term physical supply and 

demand conditions. 

Over time, some successful futures markets have 

become robust and transparent enough that their 

prices are used directly to set cash physical prices. 

For example, monthly indices used in much of the 

eastern half of the United States have become directly 

dependent on the fi nal monthly settlement price of 

futures contracts traded on the New York Mercantile 

Exchange (Nymex) to set their prices. Publishers 

of these indices use physical basis transactions to 

calculate some or all of their price indices. In effect, 

the fl ow of information regarding these physical 

prices now comes directly from futures trading. 

How to Use This Report

In the past, Commission staff produced three comprehensive State of the Markets Reports in document form, 

usually signifi cantly after the period in question. With this report, we are changing the form of the State of 

the Markets Report to take advantage of the speed and fl exibility of the Commission’s new Market Oversight 

pages on its Web site. 

These pages are available at www.ferc.gov/oversight.

Instead of providing signifi cant amounts of regional data within the report itself, the annual State of the Markets 

Report will now consist of a summary of signifi cant national electric and natural gas market developments 

over the previous year. Regional detail will be provided, and updated more regularly, within the Web pages 

themselves.

We hope that the Market Oversight section of the Commission Web site will engage stakeholders in a meaningful 

review of energy market activity by sharing much of the information we use to assess that activity. Over 

the course of the year, with the addition of information as it becomes available, we expect that the site will 

become increasingly comprehensive and useful.
FEDERAL ENERGY REGULATORY COMMISSION

888 First Street, N.E. Washington, D.C. 

Executive Summary ES-1

Section 1 Introduction 2

Section 2 Natural Gas Markets: 2005-06 5

Section 3 Electric Markets: 2005-06 12

Section 4 Infrastructure Outages and 22

Their Effects on Energy Markets

Section 5 Increasing Interdependence 29

Among Energy Markets

Section 6 Demand response in Summer 2006 38

Section 7 Growing Infl uence of Financial 43 

Energy Markets

2006 State of the Markets Report

1
2006

State of the Markets Report

FEDERAL ENERGY REGULATORY COMMISSION

www.ferc.gov/oversight

2

Natural gas and electric power markets in the 

United States responded effectively to major 

supply and demand diffi culties in 2005 and 

2006. Still, both markets face a challenging 

future in responding to increasingly integrated 

global energy markets.

Section 1 Introduction
2006

State of the Markets Report

3

FEDERAL ENERGY REGULATORY COMMISSION

www.ferc.gov/oversight

Responding to Challenges

In 2005, United States natural gas supplies faced 

unprecedented disruption from hurricanes Katrina and 

Rita. These severe supply disruptions led to sharp price 

increases that were most severe in the eastern United 

States. Nonetheless, the natural gas industry entered 

the winter of 2005-06 with strong storage inventories. 

When the winter turned out unusually mild, natural gas 

inventories remained high into 2006. High inventories 

through the year kept downward pressure on gas prices. 

Section 2, Natural Gas Markets 2005-06, describes key 

developments in natural gas markets during the year.

During summer 2006, the U.S. electric power industry 

faced a series of short, severe heat waves that affected 

almost every region. Most regions set peak load records, 

some as much as 10% above previous record loads. 

Nonetheless, the bulk power system overall suffered no 

major reliability problems, though some local distribution 

systems saw severe problems (especially in New York City 

as well as in and around St. Louis). Regional transmission 

organizations (RTOs)1

 continue to be the most important 

market institutions in the regions where they operate. 

Section 3, Electric Markets 2005-06, describes key 

developments in electric markets during 2005 and 2006. 

Market Integration

In 2005 and 2006, U.S. physical energy markets became 

more integrated, both among themselves and with global 

energy markets. Although we often consider energy 

markets as distinct (e.g., electricity and natural gas), they 

increasingly infl uence one another. Greater integration 

among physical energy markets offers signifi cant benefi ts 

to market participants and policy makers alike, but also 

presents a challenge. Key areas of integration in 2006 

included the following:

Transportation Infrastructure 

and Commodity Markets 

Even relatively small, isolated transportation network 

outages will have effects on local commodity pricing. In 

fact, one of the important characteristics of markets for 

natural gas and electric power is that they inherently signal 

tight infrastructure conditions with large price movements 

because of the short-term price inelasticity of demand for 

these products. This signaling of local market stress provides 

the logic behind locational pricing in RTOs. Section 4,

Infrastructure Outages and Their Effects on Energy Markets,

describes several examples of the effects of transportation 

infrastructure outages in 2005 and 2006:

• Coal. Two train derailments in southern Wyoming reduced 

shipments of Powder River Basin coal, starting in May 

2005. Over time, the resulting limitations reduced coal 

stockpiles for many generators, changed the generation 

mix used in some parts of the country and spurred 

changes in business strategy for some generators.

• Post-Hurricane Natural Gas Flows. Hurricanes Katrina 

and Rita severely damaged the most important natural 

gas supply basin to the eastern United States, centered 

in the Gulf of Mexico. As a result, rising gas prices in 

the East attracted more gas from Texas, loading pipelines 

heading east from Texas and leading to persistent large 

price differences between trading points in the eastern 

and western parts of the United States.

• Western Wyoming Natural Gas. Western Wyoming 

produces much more natural gas than it consumes, and 

pipeline capacity to export supplies is tight. Five times 

in fall 2006, relatively minor changes in infrastructure 

availability led to signifi cant price changes.

• Changing Electric Price Patterns Between New York 

City and Long Island. With the addition of several new 

power plants in New York City, traditional transmission 

constraints into the city diminished somewhat and the 

constraints into Long Island became comparatively more 

important. Regional real-time prices in the New York 

Independent System Operator (NYISO) area refl ected 

these changes.

1. For simplicity, this paper will refer to existing centrally managed real-time, day-ahead, and ancillary electricity markets as “RTOs” – short for “Regional Transmission 

Organizations.” In fact, we will include under that designation similar markets run by “Independent System Operators” as well.

2006

FEDERAL ENERGY REGULATORY COMMISSION
2006

State of the Markets Report

4

FEDERAL ENERGY REGULATORY COMMISSION

www.ferc.gov/oversight

Interdependence Among Energy Markets 

Section 5, Increasing Interdependence Among Energy Markets, 

shows that the interaction of markets for various fuels and 

other energy inputs created unexpected results in 2005 and 

2006:

• Integration of Natural Gas and Electric Markets. Some 

natural gas and electric markets operate over short time 

frames (often within the day) and with tight engineering 

tolerances. Natural gas is frequently the marginal (or, 

last unit chosen) fuel for power, especially when markets 

are under stress. A series of incidents show that the two 

markets must complement each other closely to maintain 

effi cient market operations and reliability.

• Natural Gas and Oil. World oil prices continue to provide 

a fl oor for U.S. natural gas prices. Even so, gas prices 

fell during 2006 below competing residual fuel oil prices 

in key downstream markets for most of the year. As a 

result, electric generators and large industrial customers 

with fuel-switching capability, primarily located in 

Florida, New York, and New England, switched to natural 

gas.

• LNG. The global liquefi ed natural gas (LNG) market 

continued to mature in 2005 and 2006. Over the long 

term, the United States will rely more heavily on LNG 

imports. Investment in new capacity continues, refl ecting 

the belief of most market participants that imports will 

increase in the future. Over the short term, competition 

for LNG supplies increased not only with Europe but also 

with Asia. Imports declined slightly for the past two 

years because of hurricane-related infrastructure outages 

in 2005 and relatively low U.S. prices in 2006.

Demand Response

Demand response helped the electric industry respond to 

the heat waves of 2006 even though most demand-response 

programs had little or no connection to the mechanics of 

electricity markets. These programs lowered peak loads, 

especially in constrained regions like Long Island and 

southwest Connecticut. Section 6, Demand Response in 

Summer 2006, reports on the experience with these programs 

in different regions. 

Physical and Financial Markets

Financial market activity increased, especially for natural 

gas. Both electric and natural gas fi nancial products saw 

increases in trading. Open interest (how many futures 

contracts remain unsettled each day) for the natural gas 

futures contract traded on the New York Mercantile Exchange 

(Nymex) increased sharply in 2006. This increase appears to 

have resulted from a continuing infl ux of both passive (e.g., 

pension funds) and active fi nancial investment (e.g., hedge 

funds). Both types of market speculation appear to have 

infl uenced prices through 2005 and 2006. 

In certain cases, prices from fi nancial markets directly set 

important physical prices. For example, monthly physical 

basis deals directly link some indexed physical natural gas 

prices to the closing price for futures trading (especially in 

the Northeast). In those cases, fi nancial prices no longer 

appear to be derivative of the physical prices, but actually 

help to set them. Section 7, Growing Infl uence of Financial 

Energy Markets, describes the interaction between physical 

and fi nancial markets in 2005 and 2006.

2006

FEDERAL ENERGY REGULATORY COMMISSION
2006

State of the Markets Report

FEDERAL ENERGY REGULATORY COMMISSION

www.ferc.gov/oversight

5

The most important factor in natural gas markets during 2005 

and 2006 was the destruction wrought by hurricanes Katrina and 

Rita. Immediately after the storms, U.S. domestic production fell 

dramatically and prices rose as a result. Through 2006, however, 

supplies have been relatively abundant and prices lower. 

What happened? The unusually mild winter of 2005-06 led to 

high gas storage inventories in early 2006. Storage levels remained 

high throughout the year, despite lower imports and higher natural 

gas use in electric generation during the summer. 

Section 2 Natural Gas Markets: 2005-06
2006

State of the Markets Report

6

FEDERAL ENERGY REGULATORY COMMISSION

www.ferc.gov/oversight

Natural Gas in 2005

Prices

Natural gas prices were rising during summer 2005, even 

before hurricanes Katrina and Rita, continuing a trend that 

began in late 2001 (see Figure 1)2. The increased prices were 

a response to many forces, including increasing crude oil 

prices (driven by world economic growth), a general decline 

in North American natural gas production since the early 

1990s, and rising demand for gas-fi red power generation. 

Hurricanes

The hurricanes damaged or destroyed signifi cant natural gas 

supply infrastructure in the Gulf of Mexico in August and 

September 2005, including onshore processing plants and 

other facilities, as well as offshore platforms and pipelines. 

The resulting production drop, 85 percent of Gulf of Mexico 

production, was historically remarkable – almost 14 times as 

much lost production from hurricane-related damage as the 

average of the 10 years before 2005 (see Figure 2). Signifi cant 

amounts of production remained offl ine well into 2006; at 

least 750 MMcfd3

 of offshore Gulf production may never 

2. Unless otherwise noted, all price data are in nominal U.S. dollars.

3. Staff phone call with Robert W. Esser, Cambridge Energy Research Associates (CERA), Jan. 3, 2007.

return. Total deliveries from interstate natural gas pipelines 

in Louisiana dropped by almost half for October 2005, and 

signifi cant volumes remained offl ine through the winter.

Prices rose signifi cantly in all regions after the hurricanes, 

but especially in areas east of the Texas-Louisiana border, 

including the entire East Coast (see Figure 3). Prices showed 

hurricane-related effects throughout the rest of 2005. 

In addition, the hurricanes disrupted natural gas markets in 

several ways, especially in Louisiana. From September 27 

through October 7, 2005, the IntercontinentalExchange (ICE) 

reported no next-day Henry Hub prices because fl ooding 

halted physical deliveries there. To manage requirements in 

the face of the facilities outage at Henry Hub, several market 

participants changed commercial arrangements, using more 

costly routing of gas to secure supplies from alternate receipt 

points. Lack of real-time information about supply chain 

availability made decision-making uncertain and may have 

increased risk premiums. 

-10

-9

-8

-7

-6

-5

-4

-3

-2

-1

0

Bcfd Procdution Changes

Katrina landfall 

8/29/05

Rita landfall

9/24/05

Wilma landfall

10/24/05

Louisiana in-state

production shut-in

OCS production shut-in

Aug-05 Sep-05 Apr-06 Oct-05 Jun-06 Nov-05 Dec-06 Jan-06 Mar-06 May-06

Pre-hurricane 

average daily 

production of

Feb-06

12.2 BcFd

Natural Gas Production Lost due to Hurricane Infrastructure 

Damage, 2005

Fig 2

Source: Derived from MMS, Hurricane Katrina/Hurricane Rita Evacuation and Production Shut-in Statistics Report.

 Henry Hub Natural Gas Daily Spot Prices, 2001-06

Derived from Platts data.

$0

$5

$10

$15

$20

Price ($/MMBtu) 

2001 2002 2003 2004 2005 2006

Natural Gas Production Lost due to Hurricane 

Infrastructure Damage, 2005

Fig 2

 Henry Hub Natural Gas Daily Spot Prices, 2001-06

Fig 1

Derived from Platts data.

Derived from MMS, Hurricane Katrina/Hurricane Rita Evaluation and Production 

Shut-In Statistics Report.

2006

FEDERAL ENERGY REGULATORY COMMISSION
2006

State of the Markets Report

7

FEDERAL ENERGY REGULATORY COMMISSION

www.ferc.gov/oversight

Natural Gas in 2006

The natural gas market recovered 

rapidly from the hurricanes, largely 

because the winter of 2005-06 was 

the fi fth warmest U.S. winter on 

record and included the warmest 

January.4

 Prices fell through 

much of 2006, rising some during 

the heat of the summer and again 

in the early winter. As has been 

typical for several years, prices 

were higher in the East than the 

West, though the East-West price 

difference was much smaller than 

immediately after the hurricanes 

(see Figure 4). 

Overall, natural gas prices remained 

higher in 2006 than in any year 

except 2005, primarily because 

world oil prices (which were high 

in 2006) appear to have prevented 

natural gas prices from falling 

further (see Section 5, Increasing 

Interdependence of Energy Markets). 

This pattern of prices across energy 

markets produced unusual supply 

and demand conditions during 

the year: high storage and a near 

glut of gas in fall 2006 along with 

high levels of drilling in the United 

States, increased electric generation 

load, and lower imports.

4. National Oceanic & Atmospheric Administration (NOAA), U.S. National Overview: January [2007] and Winter 2006, available at:

http://www.ncdc.noaa.gov/oa/climate/research/2006/feb/national.html.

$/MMBtu

13.99 to 14.57

13.49 to 13.99

12.36 to 13.49

11.09 to 12.36

9.86 to 11.09

11.57

11.16

10.61

10.78

10.81

10.81

10.13

10.79

10.83

10.76

11.28

11.11

11.48

11.55

10.89

11.63

13.61

13.61

14.28

13.88

13.37

14.57

14.23

11.39 13.39

12.39

13.14

13.25

13.31

14.03

14.01

14.14

14.03

14.41

 Average Post-Hurricane Natural Gas Prices, October 8-14, 2005

Fig 3

Source: Derived from Platts data, using Platts PowerMap.

Columbia

Waha Hub

Algonquin

Citygate

AECO Hub

Malin

Dawn

Tetco M-1

Pricing Point

Black – current price

Green – increase/previous 

year Red – decrease/previous 

 year

Basis

$7.40

($2.35)

$7.37

($2.65)

$6.96

$6.84 ($1.93)

($1.91)

$6.97

($2.22)

$6.56

($1.88)

Chicago

Citygate

Transco

Z6-NY

$6.31

($1.61)

Northern

Ventura

$6.80

($2.14)

$6.74

($1.95)

$6.36

($1.63)

Katy Hub

Henry Hub

$5.99

($1.60)

$5.90

($1.64)

El Paso

Permian

$5.89

($1.70)

Panhandle

$5.76 Tex-Okla

($1.42)

El Paso

San Juan

$6.10

($1.47)

SoCal Border

$6.47

($1.47)

PG&E

Citygate

$5.39

($1.79)

Kern River

Opal

$6.01

($1.39)

NW Sumas

$6.12

($1.46)

$5.46

($1.38)

$6.30

($1.56)

Tennessee 

Zone 0

0.19 0.63

1.10

0.66

0.62

0.71

0.20

0.36

0.33

0.24

0.66

0.11

0.37

0.19

0.06

0.40

0.12

0.28 0.03

0.10

0.06

0.37

Niagara

0.42

Fig 4

Source: Derived from Platts data. 

U.S. Natural Gas Spot Prices at Major Trading Hubs, 2006 ($/MMBtu)

Fig 4

Source: Derived from Platts data.

 Average Post-Hurricane Natural Gas Prices, October 8-14, 2005

Fig 3

Source: Derived from Platts data, using Platts PowerMap.

2006

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High Storage 

Faced with relatively low demand throughout the winter of 

2005-06, natural gas market participants drew down storage 

inventories far less than has been typical over the last 

decade. As a result, at the beginning of the 2006 injection 

season (April 1), storage inventories were 38 percent above 

the previous fi ve-year average (see Figure 5). Storage levels 

remained high throughout the summer and by October 31, 

the end of the traditional injection season, gas storage stood 

at 3,452 Bcf, only 20 Bcf short of the record high of 3,472 

Bcf set at the end of November 1990. 

Drilling and Production

In response to rising prices before the hurricanes, drilling for 

new supplies of natural gas increased (see Figure 6). Drilling 

activity remained high throughout 2006 in the United States, 

even as prices receded. Though 2006 saw more Canadian 

drilling than 2005, and both had more drilling than previous 

years, Canadian gas drilling has begun to decline in recent 

months (see Figure 7).

Production in the United States for the fi rst six months of 

2006 fell 1.3% from the fi rst half of 2005 because of lingering 

outages from the hurricanes. Nonetheless, increased drilling 

in the United States over the past few years appeared to affect 

markets (see Figure 8) as increased production made up more 

than half of the continuing hurricane-related outages. That 

is, even with the effect of the hurricanes, new production 

more than offset the effects of normal depletion, reversing 

a long-term trend, at least temporarily. Energy Information 

Administration (EIA) data for the fi rst 11 months of 2006 

show a 1.9% increase in gas production over the comparable 

2005 period.5

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

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

Bcf

5-year range, 2001-02 to 2005-06

2006-07

2005-06

2004-05

 U.S. Natural Gas Storage Inventories

Fig 5

Source: Derived from EIA Weekly Natural Gas Storage Report data.

Increased U.S. Drilling Due to Historically High 

Natural Gas Prices 

$0

$2

$4

$6

$8

$10

$12

$14

$16

2001 2002 2003 2004 2005 2006

0

200

400

600

800

1,000

1,200

1,400

1,600

Price ($/MMBtu)

Rig Count 

2000 2001 2002 2003 2004 2005 2006

Henry Hub Average Weekly Price

Gas Rigs

Source: Derived from Platts data and Baker Hughes North American Rotary Rig Count data.

 Recent Decline in Canadian Drilling

Fig 7

Source: Derived from Baker Hughes North American Rotary Rig Count data.

2004 2005 2006

Rig Count

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

0

100

200

300

400

500

600

700

5. EIA, “Table 2. Supply and Disposition of Dry Natural Gas in the United States, 2001-2006,” Natural Gas Monthly, Jan. 30, 2007, available at: http://www.eia.doe.gov/oil_gas/

natural_gas/data_publications/natural_gas_monthly/ngm.html.

Increased U.S. Drilling Due to Historically High 

Natural Gas Prices

Fig 6

 U.S. Natural Gas Storage Inventories

Fig 5

Source: Derived from EIA Weekly Natural Gas Storage Report data. 

Source: Derived from Platts data and Baker Hughes North American Rotary Rig 

Count data. 

 Recent Decline in Canadian Drilling

Fig 7

Source: Derived from Baker Hughes North American Rotary Rig Count data. 

2006

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Increased Electric Generation Load

Global oil prices remained at historically high levels through 

2006. Natural gas prices generally stayed above historical 

levels as well, but they fell below prices for residual fuel 

oil – also used to fuel power generation – for most of the 

year in key markets. As a direct result, switching to natural 

gas use from oil for electric generation increased regionally, 

especially in New York, New England, and Florida. Section 

5, Increasing Interdependence of Energy Markets, discusses 

this trend in more detail. EIA reported that generators used 

857 Bcf of natural gas in the United States in July 2006, the 

highest monthly volume for the past fi ve years.6

Lower Imports

Despite the increased use of natural gas for electric 

generation, the United States imported less natural gas 

both from Canada and from overseas as LNG (see Table 

1).7 Reductions in imports from Canada may be related to 

dropping prices and alternative uses for the gas in Canada, 

including development of nonconventional oil resources. 

LNG trends refl ect relative international prices, as discussed 

in Section 6 as well.

6. EIA, “Table 2.4.A. Natural Gas: Consumption for Electricity Generation by Sector,” Electric Power Monthly, Jan. 12, 2007, available at: http://www.eia.doe.gov/cneaf/electricity/

epm/epm_sum.html. 

7. Staff derived data from several sources. 2004 and 2005 imports are based on EIA data. The U.S. Waterborne LNG Report supplied data for 2006 LNG imports. Staff 

estimated U.S. LNG gas exports from Alaska to Japan as equal to the average of fi rst 9 months of 2006 times 12 months. Net Canadian and Mexican gas imports were 

derived from Bentek Energy information and converted into MMcf.

 Net Imports in MMcF % Change in Net U.S. Imports

 2004 2005 2006 2004-05 2005-06

Table 1: Trends in U.S. Imports of Natural Gas 2004-06

Net Canadian Imports 3,211,958 3,351,493 3,232,270 4.3% -3.6%

Net Mexican Imports (397,086) (295,634) (281,378) 25.5% 4.8%

Net LNG Imports 589,916 566,136 523,505 -4.0% -7.5%

Total Net Imports 3,404,788 3,621,996 3,474,397 6.4% -4.1%

Source: Staff analysis of EIA U.S. Natural Gas Imports by Country, Bentek Energy Import/Exports and LNG, and The U.S. Waterborne LNG Report data.

Post-Hurricane Drops, 2005-06

S D i d f Pl d B k E S l /D d B l d

2005

2006

2006 Prices

2005 Prices

Hurricane Rita

Hurricane Katrina

Hurricane Dennis

2006 Prices at Henry Hub

2005 Prices at Henry Hub

2005 2006

0

10

20

30

40

50

60

Bcfd

$0

$2

$4

$6

$8

$10

$12

$14

$16

$18

$20

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

U.S. Natural Gas Production Recovers After 

Post-Hurricane Drops, 2005-06

Fig 8

Source: Derived from Platts and Bentek Energy Supply/Demand Balance data. 

2006

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Fall 2006: Gas Glut? 

By September and October of 2006, natural gas markets 

showed signs of glut. Virtually all storage fi elds in the 

United States were full by October 26, near the end of the 

traditional injection season (see Figure 9). Prices fell as low 

as $3.66/MMBtu at Henry Hub in early October – the lowest 

level in four years. 

Through late 2006, deliveries of LNG cargoes to U.S. terminals 

dropped to low levels, though storage at LNG terminals 

remained unusually high. Some full LNG tankers even stayed 

offshore, waiting for higher U.S. prices.8

 Holding full LNG 

tankers offshore is costly, both because of the carrying costs 

of the investment in the natural gas and because some of 

the LNG evaporates while at sea. Nevertheless, the practice 

made economic sense because anticipated – and “hedgeable” 

– prices going into the winter were far higher than fall prices. 

As a result, the tankers became a form of offshore storage for 

the North American market. 

8. The U.S. Waterborne LNG Report, 2006 issues: Sept. 6; Oct. 5, 18, and 31; Nov. 10, 16, and 29; Dec. 7, 14, and 20. 

Level of gas at the storage facility

Storage capacity remaining at the facility

Fig 9

Source: Bentek Energy 

Storage levels at the End of the Injection Season, 2006

Weekly Storage Report.

Storage Levels at the End of the Injection Season, 2006

Fig 9

Source: Bentek Energy Weekly Storage Report.

2006

FEDERAL ENERGY REGULATORY COMMISSION
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Summer and Winter Price Differentials 

Price differences between summer and winter (as refl ected 

in Nymex futures prices) were higher than historical norms 

in 2006. Figure 10 shows price differentials between August 

(a representative summer month) and winter for natural 

gas going into the winters of 2006-07 and 2007-08. The 

difference between August and winter prices is (among 

other things) the valuation the market places on natural gas 

storage for the year. 

Futures prices into the future (known as the forward price 

curve through 2006) showed a premium of more than $3.00/

MMBtu in forward prices for winter 2006-07 (until the 

August contract expired at the end of July 2006 – blue line 

on the graph). Such a difference was a much higher premium 

than in the past, when premiums tended to be around $0.70 

per MMBtu. Some of the unusually high premium probably 

refl ected the overhang of gas supply in summer 2006; 

during the same months, market participants placed about 

a $2.00/MMBtu premium on winter supplies for 2007-08 

(compared to summer 2007), indicating that they expected 

the differential to fall in the following year. 

Part of the $2.00 differential for future years may also have 

been caused by transient factors, since the premium for 2007-

Price Difference ($/MMBtu) 

Difference between August and Winter

Natural Gas Futures in 2006

Source: Derived from Nymex data. 

Winter 06/07 - Aug-06 Spread

Winter 07/08 - Aug-07 Spread

Note: Winter is defined as November – March

$0

$1

$2

$3

$4

$5

Mar Apr May Jun Jul Aug Sep Oct Nov Dec

9. This may refl ect a real change in fundamentals, as the North Atlantic LNG market tends to deliver more to North America in summer and less in winter because storage is 

more abundant in North America than in Europe.

10. Rate Regulation of Certain Natural Gas Storage Facilities, Order No. 678, 115 FERC ¶ 61,343 (2006), and order on clarifi cation and reh’g, Order No. 678-A, 117 FERC ¶ 61,190 

(2006). 

08 fell to about $1.00 per MMBtu in October 2006. But even 

the remaining $1.00 differential is about $0.30 higher than 

the historical average of the years just before hurricanes 

Katrina and Rita.9 It indicates the high value that market 

participants place on natural gas storage in future years. 

In response to the need for more storage, the Commission 

undertook an initiative to encourage the development of 

more natural gas storage in coming years.10

Difference between August and Winter Natural Gas 

Futures in 2006

Fig 10

Note: Winter is defi ned as November – March

Source: Derived from Nymex data. 

2006

FEDERAL ENERGY REGULATORY COMMISSION
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12

Electric power markets responded to several important 

events during 2005 and 2006. The most signifi cant involved 

responding to changing conditions in underlying fuel 

markets, especially for natural gas and coal. In addition, 

the electric industry performed reliably in the face of several 

periods of record power generation requirements caused by 

intense heat during the summer of 2006. This section will 

review those issues and discuss developments in electric 

market institutions, both generally and within RTO markets. 

Section 3 Electric Markets: 2005-06
2006

State of the Markets Report

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Electric Market Responses 

to Fuels Markets

In 2005, wholesale, next-day, on-peak power prices ranged 

from $61.76/MWh to $110.03/MWh, up from a range of 

$42.03-$76.63 in 2004, as the prices of oil, natural gas, 

coal, and emissions allowances all increased rapidly. In 

2004 2005 2006

Table 2: Electricity Prices and Input Prices, 

2004-06 

Electric Prices ($ per MWh)

 Mass Hub $61.53 $89.94 $69.85

 Cinergy $43.33 $63.76 $51.80

 SP-15 $55.19 $73.14 $61.94

Inputs 

Natural Gas ($ per MMBtu) 

 Henry Hub $5.85 $8.69 $6.74

 New York $6.73 $10.16 $7.36

 Southern California $5.50 $7.64 $6.08

Coal ($ per ton) 

 Central Appalachian (Eastern) $54.39 $59.99 $51.64

 Powder River Basin (Western) $6.56 $9.85 $13.21

Emissions ($ per ton) 

 SO2 Allowances $442.95 $901.21 $738.12

 NOx

 allowances $2,273.77 $2,770.87 $1,862.03

Oil 

WTI (Crude - $ per barrel) $41.44 $56.48 $66.11

 Residual Fuel, NY ($/barrel) $35.13 $50.43 $55.07

 Distillate Fuel, NY ($/gallon) $1.28 $1.86 $2.04

Source: Derived from Platts, Bloomberg and Cantor Fitzgerald data. 

SO2

 prices are based on monthly averages.

2006, power prices fell, though not to 2004 levels, to a 

range of $50.12-$86.01. This decrease in power prices 

refl ected declining input prices, especially for natural gas, 

coal, and emissions allowances (see Table 2).

Generation

U.S. generation decreased by 0.1 percent in 2006 compared 

to 2005.11 Total generation was still at or near the top of the 

fi ve-year range for most of the year, except during winter 

periods when the weather was unusually warm (see Figure 

11). 

The mix of generation did change somewhat. According to 

data from EIA, overall generation in 2006 through October 

increased 0.2 percent, while gas-fi red generation increased 

6.8 percent.12 There were slight increases in nuclear and 

hydroelectric generation as well, but renewables jumped 

almost 11 percent, largely on a 47.4 percent increase in wind 

generation.13 Wind generation capacity grew by 27 percent 

in 2006 to 11,603 MW,14 representing approximately $4 

billion in additional investment. 

11. Edison Electric Institute’s (EEI) Weekly Electric Output covers the Lower 48 states only.

12. EIA, Electric Power Monthly, “Table 1.1. Net Generation by Energy Source: Total (All Sectors),” released Jan. 12, 2007, available at: www.eia.gov/cneaf/electricity/epm/table1_1.html. 

13. EIA, Electric Power Monthly, “Table 1.1.A. Net Generation by Other Renewables: Total (All Sectors),” released Jan. 12, 2007, available at: www.eia.gov/cneaf/electricity/epm/

table1_1_a.html. 

14. DOE, EERE, Wind and Hydropower Technologies Program, available at http://www1.eere.energy.gov/windandhydro/index.html, and American Wind Energy Association 

(AWEA), “Wind Energy Project Database,” as noted in press release, Jan. 23, 2007. Due to project decommissioning and repowering, the end-of-year cumulative capacity 

total does not always match the previous year’s year-end total plus additions.

 U.S. Electricity Output, 2001-06

Fig 11

Source: Derived from EEI Weekly Electric Output data.

2006

2001-05 Range

50,000

60,000

70,000

80,000

90,000

100,000

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

GWh

 U.S. Electricity Output, 2001-06

Fig 11

Source: Derived from EEI Weekly Electric Output data.

2006

FEDERAL ENERGY REGULATORY COMMISSION
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During the spring and fall of 2006, when loads are typically 

at their lowest seasonal levels, total U.S. generation was 

consistently above the fi ve-year average. Because these 

periods have less heating and cooling load, the higher 

generation levels during these periods may indicate increased 

demand due to underlying economic growth or proliferation 

of new electricity-based technologies.

Prices

Price patterns were fairly similar across the United States, 

rising in 2005 and falling in 2006 in almost all regions (see 

Figure 12), for both on-peak and off-peak deliveries (see 

Table 3 for detailed price patterns by region). Regional 

2006 declines in on-peak power prices consistently ranged 

between a quarter and a third of 2005 prices, except in 

Minnesota where the 2006 decrease ranged from roughly 15 

percent to 30 percent.15

15. Market pricing points include transactions for delivery at one or more physical locations. The map simplifi es geography by plotting a representative single location for each 

pricing point. Staff averaged prices over the 16-hour peak period.

WECC

RFC RFC

NPCC

SERC

MRO

FRCC

ERCOT

SPP

Pricing Point

Black – current price

Green – increase/previous 

year

Red – decrease/previous year

NP 15

SP 15

Four Corners

Palo Verde

COB

Mid-Columbia

Minnesota Hub

SPP

ERCOT

Entergy

Florida

TVA

Cinergy

NI Hub

PJM West

NYPP Zone G Mass Hub

NYPP Zone J

MAIN

$70.62

(19.90)

$86.97

(23.96)

$76.93

(16.15)

$62.87

(14.78)

$52.69

(12.29)

$54.06

(14.31)

$53.33

(9.49)

$64.53

(21.14)

$56.79

(13.80) $58.21

(13.27)

$56.29

(11.68)

$55.66

(9.86)

$56.54

(10.65)

$59.95

(11.06)

$59.08

(11.47)

$54.30

(11.39)

$49.28

(12.76)

$60.60

(10.28)

Source: Derived from Platts data. 

Average On-Peak Spot Electric Prices, 2006 ($/MWh) Average On-Peak Spot Electric Prices, 2006 ($/MWh)

Fig 12

Source: Derived from Platts data. 

2006

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On-Peak Spot Prices Off-Peak Spot Prices

* As of April 1, 2005, ECAR North became Michigan Hub, MAIN North became Minnesota Hub, MAIN South became Illinois Hub and MAPP North became Minnesota Hub.

Note: Table was revised March 1, 2007.

Source: Derived from Platts day-ahead peak indices and ISO average day-ahead prices.

In general, on-peak price reductions in 2006 primarily 

refl ected trends in natural gas prices. Natural gas tends to 

be on the margin for on-peak periods in most of the United 

States most of the time. Off-peak price changes in 2006 

showed more variability, falling only slightly or even rising 

in regions that depend heavily on coal. 

Table 3: On-Peak and Off-Peak Electric Prices, 2004-06

Northeast 

Mass Hub 61.47 89.87 70.33 46.2% -21.7% 42.94 61.79 47.45 43.9% -23.2%

Ny Zone G 61.74 92.46 76.53 49.8% -17.2% 42.86 63.70 50.54 48.6% -20.7%

NY Zone J 76.63 110.03 86.47 43.6% -21.4% 48.28 72.61 55.05 50.4% -24.2%

NY Zone A 52.49 76.04 59.34 44.9% -22.0% 36.82 53.26 42.20 44.6% -20.8%

PJM West 51.10 76.64 62.92 50.0% -17.9% 30.15 40.72 36.36 35.1% -10.7%

Southeast 

VACAR 48.27 71.88 57.20 48.9% -20.4% 25.23 38.13 34.96 51.1% -8.3%

Southern 48.67 70.88 56.15 45.6% -20.8% 26.01 37.54 33.86 44.3% -9.8%

TVA 44.23 67.39 53.91 52.4% -20.0% 22.14 34.24 32.76 54.7% -4.3%

Florida 58.31 84.95 65.06 45.7% -23.4% 29.02 42.88 39.78 47.8% -7.2%

Entergy 45.76 69.95 56.65 52.9% -19.0% 23.04 38.02 34.06 65.0% -10.4%

Midwest 

Cinergy 43.31 63.76 52.39 47.2% -17.8% 19.88 29.12 29.93 46.5% 2.8%

ECAR North/Michgan Hub* 45.58 67.13 55.94 47.3% -16.7% 21.00 30.84 29.30 46.9% -5.0%

MAIN North/Minnesota Hub* 47.94 64.70 58.67 35.0% -9.3% 20.28 28.78 25.73 41.9% -10.6%

NI Hub 42.03 61.76 53.15 46.9% -13.9% 17.57 28.71 28.35 63.4% -1.3%

MAIN South/Illinois Hub* 42.85 63.38 51.73 47.9% -18.4% 18.41 28.70 25.54 55.9% -11.0%

MAPP North/Minnesota Hub* 47.06 65.06 58.67 38.2% -9.8% 19.12 28.57 25.73 49.4% -9.9%

MAPP South 45.90 65.48 55.56 42.7% -15.1% 19.00 28.01 32.61 47.4% 16.4%

South Central 

SPP North 45.19 67.44 56.23 49.2% -16.6% 20.55 34.82 33.91 69.4% -2.6%

ERCOT 47.32 70.95 58.74 49.9% -17.2% 31.45 47.95 39.09 52.5% -18.5%

Southwest 

Four Corners 50.51 69.39 58.79 37.4% -15.3% 35.45 46.74 36.45 31.8% -22.0%

Palo Verde 50.09 67.39 57.85 34.5% -14.2% 35.44 47.10 36.91 32.9% -21.6%

Mead 51.91 70.18 59.79 35.2% -14.8% 37.47 49.02 38.44 30.8% -21.6%

Northwest 

Mid-C 44.54 62.95 49.52 41.3% -21.3% 39.27 50.21 37.23 27.9% -25.9%

COB 49.09 66.95 55.08 36.4% -17.7% 40.58 51.71 39.14 27.4% -24.3%

California 

NP15 54.46 72.49 60.81 33.1% -16.1% 41.35 51.35 39.17 24.2% -23.7%

SP15 55.20 73.03 61.77 32.3% -15.4% 39.26 51.22 40.07 30.5% -21.8%

2004 2005* 2006 % Change % Change 2004 2005* 2006 % Change % Change 

 $ $ $ 04-05 05-06 $ $ $ 04-05 05-06

2006

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Summer Heat Waves

Summer 2006 was notable for a few episodes of very hot 

weather, some virtually simultaneous across the United 

States, that led to short-term price increases. In the West, 

the hottest weather occurred during a single 11-day hot 

spell from July 17 to July 27. The Midwest and East saw 

three shorter periods of intense heat during June, July, 

and especially the beginning of August. 

Demand

Almost every region of the United States set records for peak 

demand during the hot weather. Every RTO set records (see 

Table 4). Most strikingly, California’s record was 10 percent 

higher than its previous peak, and that of PJM Interconnection 

LLC (PJM) was 8 percent higher (after correcting for PJM’s 

expanded geographic footprint). Even with these higher 

peaks, however, overall electric usage in the United States 

during the summer rose by only 0.6 percent. 

Peak Loads

CAISO 45.4 50.3 10.7% July 24

ERCOT 60.3 62.3 3.3% August 17

SPP 40.5 42.2 4.2% July 19

MISO 112.2 116.3 3.7% July 31

PJM 133.8 144.6 8.1% August 2

NYISO 32.1 33.9 5.6% August 2

ISO-NE 26.9 28.1 4.5% August 2

Table 4: New RTO Record Loads Set, 2006

RTO Pre-06 2006 Increase 2006 Peak

 (GW) (GW) % Date

Source: Derived from RTO data, using hourly integrated peak loads.

Reliability and Emergency Actions

The U.S. bulk power system met the load requirements during 

the record-breaking heat. There were no blackouts at the 

wholesale level – though there were some severe distribution 

outages, especially in the St. Louis area and New York City. 

In all RTOs, administrative actions and other reliability 

actions were used to manage the loads. 

Emergency Actions. Grid operators in all RTO regions 

made use of various administrative actions as well as 

market forces to ensure continuing service during the 

heat waves. These actions included issuing operational 

warnings, engaging in emergency transactions, and calling 

on demand response. Grid operators in California, PJM, 

New York, and New England cited two major factors in 

maintaining the bulk power system – demand response and 

unprecedented generator availability. Demand response was 

particularly important in several vulnerable regions – Long 

Island, southwest Connecticut, and California (see Table 

5).16 Section 6, Demand Response in Summer 2006, discusses 

demand response in more detail. 

16. The responses include distributed generation and conservation.

 Region Peak Load Demand Response

Long Island 5,684 August 2 261 4.6%

Southwest Connecticut 3,701 August 2 227 6.1%

California 50,270 July 24 2,066 4.1%

(MW) Date (MW) (% of peak)

Source: Derived from RTO data and and Connecticut Valley Exchange data.

Table 5: Demand Response in Vulnerable 

Regions, Summer 2006

2006

FEDERAL ENERGY REGULATORY COMMISSION
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Importance of Preparation. During 2006’s high-heat periods, 

grid operators responded best when they were prepared for 

the stress. When the grid operators were not as prepared, 

some problems arose. For example:

• New York faced its fi rst hot weather during the week 

after Memorial Day. On May 30, NYISO went forward 

with a planned improvement to its real-time software, 

which took its real-time market offl ine for four hours 

during the fi rst day of highly volatile prices, thereby 

eliminating the market during the period when it should, 

in theory, have been most valuable.

• In Texas, the Electric Reliability Council of Texas (ERCOT) 

ordered rolling blackouts on April 17 for about two 

hours. The Public Utility Commission of Texas faulted 

unseasonably high temperatures, a low demand forecast, 

large but normal planned generation outages (nearly 

14,500 MW), and unplanned outages of 2,440 MW. 

Prices During Hot Weather

Prices rose to very high levels at some times during the 

heat waves in both bilateral and RTO markets, as is typical 

for electric power markets. In eastern RTO markets, realtime prices rose dramatically during the heat waves (with 

the exception of July 21 when, even with cooler weather, 

a combination of unplanned outages and a thunderstorm 

alert drove prices in New York City higher), refl ecting higher 

demands on the systems. Figure 13 shows the range of 

eastern RTO real-time prices during summer 2006. 

Despite the long period of high temperatures during July 

17-27, western U.S. prices reached very high levels only on 

July 24 (for July 25 delivery), power that traded during the 

day of highest regional peak demand. Day-ahead bilateral 

markets – which traded on Friday, July 21, for power use on 

Monday, July 24, did not anticipate the full severity of the 

demand. The WECC forecasted a peak demand for July 24 

at 150.4 GW for the entire western region; the July 24 actual 

peak was actually 159.2 GW.17 Figure 14 shows the range of 

summer 2006 daily on-peak prices at western trading hubs.

17. Western Electricity Coordinating Council, Daily Reports, July 21 and July 25, 2006.

7/31-8/3

5/31-6/1 7/17-7/19

Price ($/MWh)

Range is real-time hourly 

RTO prices in the East, 

averaged over 24 hours. 

Real-Time Electric Prices in Eastern U.S. Markets,

Summer 2006

Fig 13

Source: Derived from RTO data using ISO-NE Mass Hub, NYISO Zone J, PJM Western 

Hub, and MISO Cinergy Hub. 

$0

$50

$100

$150

$200

$250

$300

$350

$400

May-06 Jun-06 Jul-06 Aug-06

7/17-7/27

Range is day-ahead 

bilateral trading prices for 

major Western hubs.

Price ($/MWh)

Day-Ahead Peak Electric Prices in Western 

U.S. Hubs, Summer 2006

Fig 14

Source: Derived from ICE data using COB, Four Corners, Mid-Columbia, Mona, NOB, 

NP-15, SP-15, and Palo Verde Hubs. 

$0

$50

$100

$150

$200

$250

$300

$350

$400

May-06 Jun-06 Jul-06 Aug-06

Real-Time Electric Prices in Eastern U.S. Markets, 

Summer 2006

Fig 13

Source: Derived from RTO data using ISO-NE Mass Hub, NYISO Zone J, PJM 

Western Hub, and MISO Cinergy Hub. 

Day-Ahead Peak Electric Prices in Western 

U.S. Hubs, Summer 2006

Fig 14

Source: Derived from ICE data using COB, Four Corners, Mid-Columbia, Mona, 

NOB, NP-15, SP-15, and Palo Verde Hubs. 

2006

FEDERAL ENERGY REGULATORY COMMISSION
2006

State of the Markets Report

18

FEDERAL ENERGY REGULATORY COMMISSION

www.ferc.gov/oversight

Transactions above the $400 

Western Price Cap

A review of the Commission’s Electric Quarterly Report (EQR) 

showed a small number of transactions in the West at prices 

above the applicable price or offer cap, representing less 

than 0.1% of all the power that fl owed during the peak hour 

of that day. Unlike the $1,000 offer cap in the East, the cap 

in the West is soft – the Commission can accept the prices 

or offers given adequate justifi cation.18 About 70 percent 

of the apparently above-cap prices in the West through the 

summer occurred on the peak load date of July 24. 

RTO Scarcity Pricing

During the summer heat, NYISO and ISO New England (ISONE) both invoked scarcity pricing (see Table 6). NYISO’s 

scarcity pricing sets the clearing price at the higher of the 

locational price or the scarcity resource offer, based on an 

imputed demand curve. ISO-NE’s version sets the clearing 

price at $1,000/MWh. 

18. Cal. Indep. Sys. Operator Corp., 114 FERC ¶ 61,026, at 25-26 (2006) (raising the soft cap in WECC to $400/MWh from $250/MWh, but denying CAISO’s request to 

make it a hard cap during the transition period to its MRTU).

19. David B. Patton, “Independent Market Monitor Review: 2006 Peak Load Event,” PowerPoint presentation to the MISO Board of Directors Markets Committee, Sept. 20, 2006, p. 3.

20. Staff analysis of CAISO data.

21. Staff analysis of NYISO data. NYISO said unusual weather conditions on Aug. 2 contributed to this output. Averaged between 2 p.m. through 6 p.m. during June, July and 

August, wind production was 18.6 percent of capacity (Feb. 5, 2007, e-mail from NYISO to staff).

22. Staff analysis of MISO data.

Region/Date Duration Prices Areas Affected

Table 6: Implementation of Scarcity Pricing in NYISO and ISO-NE, Summer 2006

NYISO 

 July 18 9 hours $500-$1,000/MWh Eastern zones

 August 1 5 hours $500-$1,500/MWh New York City, Long Island

 August 2 6 hours $500-$1,500/MWh Western zones, New York City, Long Island

 August 3 6 hours $500-$1,000/MWh New York City, Long Island

ISO-NE 

 August 1 2 hours $1,000/MWh All zones, except Maine

 August 2 5 hours $1,000/MWh All zones

Source: Derived from RTO data. 

MISO and PJM did not invoke scarcity pricing, though 

prices rose to very high levels in some locations. However, 

the MISO Independent Market Monitor reported that MISO 

avoided shortage conditions that would have resulted in 

prices at or near scarcity levels only because of the nonmarket emergency actions it took.19

Performance of Renewable Sources of 

Generation at the Peak 

Renewables contributed to peak demands in different ways 

across the United States. In California, heat was combined 

with humid, stagnant air, resulting in low levels of wind 

generation. Averaged over the peak day, wind output was 

less than 15 percent of total wind capacity, contributing 

about 380 MW to the system.20 In New York, almost 54 

percent of wind generating capacity was produced on the 

peak day, contributing 149 MW.21 In the Midwest, almost 

two-thirds of wind generating capacity was used on the peak 

day, contributing 542 MW.22 

2006

FEDERAL ENERGY REGULATORY COMMISSION
2006

State of the Markets Report

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FEDERAL ENERGY REGULATORY COMMISSION

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Current Market Institutions

The largest regional difference in electric power market 

structure is between those regions that rely primarily on 

bilateral markets (the Southeast and the West outside 

California) and the rest of the country that relies largely 

on RTOs (see Table 7). RTOs operate the most infl uential 

markets for power (or imbalance energy in the case of 

CAISO, ERCOT, and SPP) in the regions they cover. In 

those regions, bilateral physical markets closely track 

analogous RTO markets, and fi nancial instruments tend 

to settle against RTO markets, not bilateral markets. RTO 

markets provide far more information than other markets, 

especially about the locational value of the commodity. 

In general, RTO and bilateral markets both produce prices 

that largely refl ect the cost of fuel for marginal units.

Most RTO markets share some basic characteristics. 

Typically, they have day-ahead and real-time markets, 

based on security-constrained, optimal dispatch of 

generating units (CAISO, ERCOT, and SPP have no dayahead market). The RTO markets have many differences 

of detail, but they are far more similar to each other than 

to the power markets in non-RTO regions. 

Outside the RTOs, in the West, long-distance transmission 

and trading are essential for the entire region. Fairly deep 

and liquid bilateral spot markets exist both inside and 

outside California, especially for day-ahead power. These 

Real-time Day-ahead Virtual Ancillary Financial Capacity Associated 

 market market Bidding services transmission (UCAP) fi nancial 

 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 08 

Southeast 

SPP 

ERCOT 09 

Northwest 

Southwest 

California 08 09 4 

Table 7: Wholesale Electric Markets in 2006

1 Transitioning to a formal capacity market. ISO-NE’s installed capacity market was replaced on December 1, 2006, with the transition period for its 

 new Forward Capacity Market. 

2 Locational 

3 Systemwide

4 California is considering a formal capacity market.

Source: Staff analysis of RTO rules.

Existing Projected 

2006

FEDERAL ENERGY REGULATORY COMMISSION
2006

State of the Markets Report

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FEDERAL ENERGY REGULATORY COMMISSION

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23. Commission Convenes Series of Public Conferences to Examine State of the Competitive Markets, press release issued Dec. 19, 2006, available at: http://www.ferc.gov/pressroom/press-releases/2006/2006-4/12-19-06.asp.

24. Southwest Power Pool Inc., 118 FERC ¶ 61,055 (2007) (fi nding SPP’s Market Readiness Certifi cation on its energy imbalance market in compliance with requirements of 

previous orders, and accepting SPP’s Certifi cation fi ling).

25. id.

26. Cal. Indep. Sys. Operator Corp., 116 FERC ¶ 61,274 (2006). 

27. Texas Public Utility Commission, Project 26376, September 2003, included an order to ERCOT to develop a nodal market. ERCOT is running twelve concurrent projects to 

move toward its anticipated 3Q 2009 “Nodal Go Live.”

28. Commission denies rehearing of New England’s Planned Forward Capacity Market; Proposed Tariff Accepted, press release issued Nov. 1, 2006; Devon Power LLC, 115 FERC ¶ 

61,340 (2006), order on reh’g, 117 FERC ¶ 61,133 (2006).

29. PJM Interconnection L.L.C., 117 FERC ¶ 61,331 (2006) (denying rehearing and approving settlement subject to conditions).

markets provide price discovery throughout the region, 

including for day-ahead transactions in California. In 

the Southeast, bilateral markets have few liquid trading 

points (into-Entergy is a partial exception) and little 

transparency.

The Commission initiated a series of conferences to 

examine competitiveness in electric power markets on 

December 19, 2006.23 The conferences will explore many 

issues, including federal-state cooperation, the need for 

new infrastructure, demand response and renewable 

energy, the availability of long-term contracts, and 

market design issues affecting wholesale markets. The 

conferences will consider issues in all wholesale markets, 

both bilateral and within RTOs. 

RTO Developments

No new RTOs came into existence in 2005 or 2006, 

although MISO began operation of its energy market on 

April 1, 2005, and SPP inaugurated its imbalance markets 

on February 1, 2007.24 Geographically, Duquesne Light 

joined PJM on January 1, 2005; Dominion Power joined 

PJM on May 1, 2005; and Louisville Gas & Electric and 

Kentucky Utilities withdrew from MISO on September 1, 

2006. Most market characteristics in established RTOs 

remained stable (see Table 8). However, RTOs continued 

to evolve in several signifi cant ways. 

Three regions announced plans for major new market 

initiatives. As noted, SPP began its voluntary realtime locational marginal price (LMP) energy imbalance 

market on February 1, 2007.25 CAISO currently intends to 

implement its “Market Redesign and Technology Upgrade” 

(MRTU) proposal in 2008.26 The MRTU proposal includes 

a day-ahead energy market, LMP, co-optimization of 

energy and ancillary services, a backstop reliability 

commitment protocol, and redesigned transmission rights. 

ERCOT announced its intent to implement nodal pricing 

for generators by 2009 and raise its offer limit in stages 

to $3,000/MWh for energy and $3,000/MW for ancillary 

services.27

Capacity Markets

Several RTOs have taken steps to encourage that investment 

in resources is adequate to meet peak demands in the future. 

To address that need, ISO-NE developed a new Forward 

Capacity Market (FCM).28 ISO-NE will project the needs of 

the power system three years in advance and hold an annual 

auction to buy power resources to satisfy the needs. The fi rst 

payments under FCM should begin in 2010-11. Similarly, 

the Commission acted on PJM’s proposed new Reliability 

Pricing Model (RPM) on December 21, 2006.29 Several factors 

would affect pricing, including a sloped (assumed) curve for 

demand, location, and a forward commitment requirement 

for capacity.

2006

FEDERAL ENERGY REGULATORY COMMISSION
2006

State of the Markets Report

FEDERAL ENERGY REGULATORY COMMISSION

www.ferc.gov/oversight

21

Existing Projected  Cost-Based  Other

Bilateral transactions 

Active online physical trading 

Active online fi nancial trading 

Real-time energy market 1

 2 

 Locational energy price 

 Hourly energy price 

 Congestion price 

 Losses price 07 3 4 5

Day-ahead energy market 1

 09 08

 Locational energy price 09 08

 Hourly energy price 09 6 08

 Congestion price 09 7

 Losses price 07 3 08

Ancillary services market 08  

Regulation service market 8   

Operating reserves market 9 10  

Reactive power market 11 12     

Black start market     13 

Financial transmission rights 7

Capacity market 14 15 16

Regional transmission scheduling 

Regional economic dispatch 17 17

Regional transmission planning 

Regional interconnection process 

Independent market monitor 

Mitigation 

Table 8: RTO Market Characteristics in 2006

 1 NYISO’s Real Time Commitment model considers energy reserve and regulation when calculating prices. 

 2 The SPP market is limited to an imbalance energy market.

 3 Losses currently allocated to market participants based on a pro-rata share of total transmission losses. Marginal losses will be charged 

 starting June ’07.

 4 Consumers also have the option to settle their losses by self-supply.

 5 Allocated to sellers using generation meter multipliers, which refl ect scaled marginal losses. 6 15 minute settlement instead of hourly.

 7 To be revised in 2008 under MRTU.

 8 Offers from AEP and Dominion are cost-based, and all other are market-based.

9

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

10 Maintained by Balancing Authorities. When provided from generating resources, an hourly MW schedule for capacity is submitted to MISO. 11 Participants capable of providing reactive power do not bid into the market. If called upon to provide this service, they are paid the energy 

 clearing price if taken in merit or uplift if taken out of merit. 

12 Fixed monthly Mvar payment plus opportunity cost. 

13 RFP procurement process. 

14 ISO-NE’s installed capacity market was replaced on December 1, 2006, with the transition period for its new Forward Capacity Market. 15 Replacement market buys generation for short term market to satisfy local congestion and system-wide capacity shortages.

16 CAISO has cost-based contracts for RMR. California is considering a formal capacity market. 

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

Services Provided ISO-NE NYISO PJM MISO SPP ERCOT CAISO

Source: Staff analysis of RTO rules.
2006

State of the Markets Report

FEDERAL ENERGY REGULATORY COMMISSION

www.ferc.gov/oversight

22

Section 4 Infrastructure Outages and 

 Their Effects on Energy Markets

Even relatively small, isolated transportation network outages can 

have major effects on commodity pricing. In fact, one of the important 

characteristics of markets for natural gas and electric power is that they 

inherently signal tight infrastructure conditions with price changes. 

In 2005 and 2006, energy markets provided numerous examples of 

prices signaling infrastructure constraints. In this section, we will 

consider constraints due to rail outages limiting coal deliveries to electric 

generators, hurricane damage to natural gas supply, pipeline capacity 

constraints on deliveries of natural gas from western Wyoming, and 

problems with electric supply into New York City and Long Island.
2006

State of the Markets Report

23

FEDERAL ENERGY REGULATORY COMMISSION

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30. EIA, Electric Power Annual 2005, “Figure ES 1. U.S. Electric Power Industry Net Generation.” 

31. Platts CoalDat, September 2006 release.

32 The Senate Energy and Natural Resources Committee held hearings focused on coal supplies on May 25, 2006. The Senate Energy and Natural Resources Committee, 

subcommittee on surface transportation and merchant marine held a hearing on the economics, service, and capacity in the freight railroad industry on June 21, 2006. 

The House Transportation and Infrastructure Committee, subcommittee on railroads, held a hearing on railroad capacity on April 26, 2006.

33. Discussions with Utility and Railroad Representatives on Market and Reliability Matters, Docket No. AD06-8-000, June 15, 2006. Representatives from the major electric 

associations and railroads testifi ed at this public meeting.

34. Derived from data on Union Pacifi c (UP) website: “UP Coal Loading Performance Data for the Powder River Basin,” available at: http://www.uprr.com/customers/energy/

sprb/weekly.shtml and “Updates Regarding UP Rail Service,” available at: http://www.uprr.com/customers/energy/sprb/updates.shtml. 

35. EIA, Weekly and Monthly U.S. Coal Production Overview, Dec. 30, 2006.

36. EIA, Monthly Flash Estimates of Electric Power Data, “Table 6.1 Trends in Total Fossil Fuel Stocks (Electric Power Sector),” Jan. 19, 2007.

37. Pace Global Energy Services LLC, PRB Coal Transportation: Still a Hot Issue, June 2006.

1,500

1,600

1,700

1,800

1,900

2,000

2,100

2,200

2,300

JanFebMarAprMayJunJulAugSepOctNovDecJanFebMarAprMayJunJulAugSepOctNovDec

Derailments on 

the Joint Line 

Southern PRB Coal Trains per Month

2005 2006

J F J M A M J A S O N J D J F M A M J A S O N D

Coal Loadings Recover in 2006 

After May 2005 Derailments

Source: Derived from Union Pacific and BNSF Railway Company data. 

Coal Loadings Recover in 2006 After May 2005 

Derailments

Fig 15

Source: Derived from Union Pacifi c and BNSF Railway Company data. 

2006

FEDERAL ENERGY REGULATORY COMMISSION

Rail Outages Impair Coal Supplies

In 2005, major rail outages reduced deliveries of Wyoming’s 

Powder River Basin (PRB) coal to electric generators. The 

resulting reductions in coal deliveries forced short-term 

changes in electricity markets and generation patterns. 

Over the longer term, markets responded as the railroads 

repaired damage and added new infrastructure, and 

customers devised ways to reduce their dependence on 

PRB coal.

PRB Coal and U.S. Electric Generation

Coal is the fuel for about half of all electric generation in the 

United States.30 PRB coal accounted for about 34 percent 

of U.S. coal production in 2005.31 In May 2005, the rail 

line leading south from the basin, the Joint Line, suffered 

two derailments, reducing the ability to deliver PRB coal to 

U.S. markets for more than a year (see Figure 15). In the 

short run, generators responded to the resulting disruptions 

by conserving coal, drawing down stockpiles, and importing 

more coal. 

Concern by some market participants about coal logistics 

and electric reliability prompted congressional hearings from 

April through June 2006.32 The Commission hosted a June 

15, 2006, discussion with utility and railroad representatives 

on the market and reliability issues related to the outage and 

coal transportation issues.33

Recovery

By Fall 2006 the railroads had restored, and even augmented, 

delivery service from the basin. PRB carloadings set record 

highs in 2006. Union Pacifi c (UP) increased average trains 

per day out of the southern PRB by 7 percent, up from 32.8 

trains per day in 2005 to 35.3 between 2005 and 2006.34

Improved rail performance in 2006 coincided with, and 

may have been partially responsible for, several other coal 

industry developments. Wyoming coal production rose by 

42 million tons, or 10.3 percent, in 2006 to 446 million 

tons.35 Generators rebuilt their coal stocks. By the end of 

November 2006, electric power coal stocks reached 139.5 

million tons, 31 percent more than a year earlier.36 Over the 

longer run, coal customers have begun fi nding new ways to 

manage PRB supply risks including blending PRB coal with 

other coals, relying more heavily on imports, and switching 

to alternate coal supplies.37
2006

State of the Markets Report

24

FEDERAL ENERGY REGULATORY COMMISSION

www.ferc.gov/oversight Price ($/MMBtu) 

Gap Between Texas and Henry Hub Prices Widened

After Hurricanes

Fig 17

Houston Ship

Channel

Texas Eastern

(South Texas)

2005 2006

J A F J M M O J D A S NJ A F J M M S J A O

Source: Derived from ICE data. 

-$4.50

-$4.00

-$3.50

-$3.00

-$2.50

-$2.00

-$1.50

-$1.00

-$0.50

$0.00

$0.50

10.89

13.37 13.71

13.88

14.28

14.31

13.99

13.72

13.53

13.61

13.39

13.61 13.71 13.04

13.63

13.34

13.49 13.84 13.58

11.63

11.55

11.58

11.09

13.27

$/MMBtu

13.99 to 14.57

13.49 to 13.99

12.36 to 13.49

11.09 to 12.36

9.86 to 11.09

TEXAS LOUISIANA

MISSISSIPPI

ARKANSAS

Sabine River

Fig 16

Average Post-Hurricane Natural Gas Prices,

October 8-14, 2005

Source: Derived from Platts data, using Platts PowerMap.

Gap Between Texas and Henry Hub Prices Widened 

After Hurricanes

Fig 17

Source: Derived from ICE data. 

Average Post-Hurricane Natural Gas Prices, 

October 8-14, 2005

Fig 16

Source: Derived from Platts data, using Platts PowerMap.

2006

FEDERAL ENERGY REGULATORY COMMISSION

Congestion in Natural Gas

and Resulting East/West

Price Divergence

After hurricanes Katrina and Rita, gas supplies declined 

severely in Louisiana, and customers attempted to move 

supplies from East Texas into Louisiana for delivery farther 

east and north. The resulting congestion caused a large, 

persistent price difference between Texas and Louisiana. 

With returning production in Louisiana, price differences 

moderated. 

The Sabine River Divide

After hurricanes Katrina and Rita, U.S. natural gas prices 

separated between East and West, with the most striking 

difference along the Sabine River boundary between Texas 

and Louisiana (see Figure 16). East of the Sabine River, in 

Louisiana, prices rose to as much as $4/MMBtu higher than 

west of the Sabine River in Texas. 

Historically, price differences from Texas into Louisiana 

were low through 2002 and grew somewhat after that. By 

2004, the average price at Henry Hub was about $0.15 

higher than at Houston Ship Channel, largely because 

of increased production in Texas (e.g., Barnett Shale) and 

falling production in Louisiana. 

Occasionally in the past, the price differences across the 

Sabine River boundary have risen for short periods of time. 

The differences after the hurricanes were larger and lasted 

much longer than in the past (see Figure 17) – enough to 

raise the average difference from the Houston Ship Channel 

to Henry Hub to $0.78 for all of 2005, a fi ve-fold increase 

from 2004. 

The storms affected far more production and other 

infrastructure onshore and offshore in Louisiana than Texas. 

Customers from the East tried to move receipt points and 

buy as much Texas gas as they could to fl ow east. Once 

pipeline capacity was congested, prices between the two 

regions broke apart and stayed apart for several months.
2006

State of the Markets Report

25

FEDERAL ENERGY REGULATORY COMMISSION

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38. FERC’s Offi ce of Energy Projects provided the pipeline expansion data. About 6,000 MMcfd of capacity has been announced; 2,812 MMcfd has been applied for; and 6,737 

MMcfd has been approved. 

2006

FEDERAL ENERGY REGULATORY COMMISSION

Market Responses

Price differences between East Texas and Louisiana pricing 

points narrowed in 2006. In response to the continuing 

tightness of pipeline capacity heading east into Louisiana, 

as well as the possibility of future hurricanes, pipeline 

companies proposed several projects for more capacity (see 

Table 9).38

 Developer Project Status Date Filed Date Final Year Cost Added Beginning Ending

 With FERC Approval Scheduled (Million $) Capacity State State

 by FERC for Service (MMcfd) 

Gulf South Pipeline Co. Gulf South Carthage to Applied 14-Apr-06 -- 2006 47.9 122.4 TX LA

 Keatchie Pipeline Loop

Kinder Morgan Energy KMP Carthage Line Announced -- -- 2007 50 700 TX LA

Partners

Sabine Pipeline LLC Sabine Henry Hub Announced -- -- 2007 5 50 TX LA

 Expansion

Gulf South Pipeline Co. Gulf south Texas to Applied 01-Sep-06 -- 2007 766.9 1,700 TX MS

 Mississippi Expansion

Trunkline Gas Co. Trunkline north Texas Applied 11-Sep-06 -- 2007 159 510 TX LA

 2007 Expansion

CenterPoint Energy CEGT Perryville Expansion Approved 10-Mar-06 02-Oct-06 2007 404 1,237 TX LA

Gas Trans. Phase 1 & 2

CenterPoint Energy CEGT Perryville Expansion Applied 15-Dec-06 -- -- 39 280 TX LA

Gas Trans. Phase 3

Boardwalk Pipeline Gulf Crossing Pipeline Announced -- -- 2008 800 1,000 TX LA

Partners LP Project

CenterPoint Energy CEGT Mid-Continent Announced -- -- 2008 2,000 1,750 TX PA

Gas Trans. Crossing (MCX)

Kinder Morgan Energy KMP Mid-Continent Announced -- -- 2008 1,750 1,500 TX AL

Partners Express

Nat Gas PL Co. NGPL Louisiana/Gulf Applied 10-Oct-06 -- 2008 66 200 TX LA

of America Coast Line Expansion 

Golden Pass LNG Golden pass LNG Approved 26-Jul-04 30-Jun-05 2008 328 2,500 TX LA

Terminal LP Northern Line

Port Arthur Pipeline LLP Port Arthur LNG Laterals Approved 28-Feb-05 14-Jun-06 2008 217 3,000 TX LA

 Phase 1

Enbridge Energy Enbridge TX-MS Pipeline Announced -- -- 2009 400 1,000 TX MS

Pipeline Co.

Source: Staff analysis of FERC Offi ce of Energy Projects data and EIA, Pipeline Expansion Database.

Table 9: Proposed Texas Natural Gas Infrastructure Projects
2006

State of the Markets Report

26

FEDERAL ENERGY REGULATORY COMMISSION

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39. The gathering system outage would have the opposite effect of pipeline outage because it reduced supplies available to be taken to market. 

Export Capacity from the Western Rockies, 2006

Fig 18

Northwest 

WY

Pool

Kern River

Opal Plant

Questar

Rocky

Mountains

Northwest South 

of Green River

Cheyenne

Hub

PSCo

Citygate

Event - Description

1

2

3

4

5

Northwest Pipeline Outage

Jonah Gathering Maint.

Opal Maint.

Nov 8 Price Collapse

WIC Explosion 5

3

4

2

1

Cheyenne Plains

CIG

Kern River

NW Pipeline

Southern Star

PSCo

Questar

KMI

TransColorado

Williston Basin

WIC

Pipeline Companies

Gas Pricing Points

Source: Staff analysis of Bentek Energy data, created using Platts PowerMap.

Export Capacity from the Western Rockies, 2006

Fig 18

Source: Staff analysis of Bentek Energy data, created using Platts PowerMap.

2006

FEDERAL ENERGY REGULATORY COMMISSION

 Pipeline Capacity Constraints 

from Western Wyoming

Lack of pipeline capacity to fl ow gas from western 

Wyoming to market was a chronic issue early in the 

present decade and often led to low prices in the area. 

(In a producing region, a shortage of capacity capable 

of moving the gas out, also called take-away capacity, 

can effectively create a local glut as too much gas is 

available for the available outlets to market.) During 

the last fi ve years, the price disparity between western 

Wyoming and its major markets eased most of the time 

because Kern River Pipeline and Cheyenne Plains Pipeline 

added capacity out of western Wyoming to both southern 

California and eastern markets (see Figure 18). 

However, the balance between production and take-away 

capacity in the Rockies grew tighter, especially in 2006. 

Estimated daily gas supplied by key Rockies basins – UintaPiceance, Green River-Overthrust, Denver-Julesberg, 

and Powder River – increased by about 1 Bcf per day 

in 2006, while related take-away pipeline capacity was 

unchanged. As a result, on fi ve occasions in Fall 2006, 

relatively small pipeline outages led to brief but severe 

price volatility in the area (see Figure 19).39 Because the 
2006

State of the Markets Report

27

FEDERAL ENERGY REGULATORY COMMISSION

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outages were relatively small (especially in the context 

of the wider western market), the outages had no major 

effect on prices in major market areas. 

• September 14-19. Planned maintenance on the southern 

leg of Northwest Pipeline curtailed gas taken from Wyoming 

and Colorado to markets in Arizona and California. The 

outage totaled 350 MMcfd. All other pipelines were full. 

Western Wyoming prices fell by an average of $2.16/

MMBtu for four days. (See Event 1 on Figure 18)

• October 4-5. Planned maintenance on the Jonah Gathering 

system reduced receipts into pipelines by 272 MMcfd. The 

relative shortage of gas for two days led to a noticeable 

price increase. (See Event 2 in Figure 18)

• October 6-9. Planned outage at the Opal, Wyoming, plant 

on Kern River Pipeline reduced take-away capacity by 210 

MMcfd, about 3 percent of total capacity. All remaining 

pipeline capacity was full. Prices fell an average of $2.96/

MMBtu. (See Event 3 on Figure 18) 

• November 8. Pacifi c Gas & Electric issued a high inventory 

operational fl ow order; there was too much gas on its 

system relative to light gas demand. Reduced California 

gas requirements coupled with limited ability for new local 

Rockies storage, contributed to a 150 MMcfd reduction in 

throughput on the Kern River Pipeline. (See Event 4 on 

Figure 18)

• November 11. An accident on Wyoming Interstate 

Company (WIC) reduced gas fl ows by 765 MMcfd. Prices 

fell by an average of $3.26/MMBtu at western Rockies 

points. (See Event 5 on Figure 18)

Market Response

Market participants recognized the need for more pipeline 

capacity leaving western Wyoming. About 3 Bcf of 

incremental pipeline capacity is in various stages of 

development, with about 1.7 Bcf approved and under 

construction. 

asdf

Cheyenne Opal

Explosion

Fundamentals

Maintenance

 Maintenance Affects Wyoming Gas Prices, 2006

Fig 19

Source: Derived from ICE data and Bentek Energy pipeline notices. 

$0

$1

$2

$3

$4

$5

$6

$7

$8

Aug-06 Sep-06 Oct-06 Nov-06

Price ($/MMBtu) 

 Maintenance Affects Wyoming Gas Prices, 2006

Fig 19

Source: Derived from ICE data and Bentek Energy pipeline notices. 

2006

FEDERAL ENERGY REGULATORY COMMISSION
2006

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FEDERAL ENERGY REGULATORY COMMISSION

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Electric Power Issues: 

New York City and Long Island

Traditionally, New York City and Long Island have had the 

highest power prices in the NYISO. From 2000 through 

2005, the differences between the two areas and the rest 

of New York grew at roughly the same rate. In 2006, 

the price differences between New York City and the rest 

of the state declined considerably, while the difference 

between Long Island and other areas continued to grow 

(see Figure 20).

The largest change between 2006 and 2005 affecting 

relative prices between New York City and Long Island 

was the addition of generating capacity in New York 

City (see Figure 20, inset).40 Between the peak summer 

seasons of 2005 and 2006, New York City added 1,299 

MW of capacity, about 14 percent of the previous total. 

By contrast, Long Island added only 488 MW (9 percent 

of previous capacity).41 Adding capacity in New York 

City appears to have improved the balance of supply and 

demand in the City, putting downward pressure on prices. 

Indeed, on one day during 2006, New York City faced 

transmission constraints on sending power north out of 

the city for the fi rst time ever.42 Increased generation 

in the city also helped it weather a major transmission 

Price Differences ($/MWh)

Fig 20

Large Generation Additions Reduced 

New York City Price Premium, Summer 2006

Source: Derived from NYISO data. 

Long Island minus Rest of State, Day-Ahead

Long Island minus Rest of State, Real-Time

NYC minus Rest of State, Day-Ahead

NYC minus Rest of State, Real-Time

Capacity Additions (MW) 2005 2006

New York City 292 1,007

Long Island 488 0

$0

$5

$10

$15

$20

$25

$30

1999 2000 2001 2002 2003 2004 2005 2006

outage during the summer. With the new generation, 

New York City was able to manage a series of outages 

on two 345-kV transmission lines serving New York 

City starting in June and continuing through July 17.43

During the July heat wave, New York City did experience 

local distribution outages that affected 25,000 customers 

in northwest Queens.44 

40. Prices in New York City and Long Island refl ect several factors besides relative supply and demand in the two areas – for example, losses, price mitigation in New York City, 

and scarcity pricing in both areas. Capacity additions include generation and transmission.

41. The Cross Sound Cable was energized in 2005, although it had previously been in place.

42. Monthly Staff conference call with NYISO, June 7, 2006.

43. The outages probably did not contribute to the change in relative prices between New York City and Long Island. They would have tended to worsen the supply-demand 

balance in the city, putting upward pressure on prices there.

44. Consolidated Edison, “Initial Report on the Power Outages in Northwest Queens in July 2006,” Aug. 2, 2006.

Large Generation Additions Reduced New York City 

Price Premium, Summer 2006

Fig 20

Source: Derived from NYISO data. 

2006

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2006

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2006

In 2005 and 2006, U.S. physical energy markets became 

more integrated, both among themselves and with global 

energy markets. Although we tend to consider energy 

markets as distinct (e.g., electricity or gas), they 

increasingly influence one other. Key areas of integration 

evident in 2006 included natural gas and electric markets, 

natural gas and oil markets, and global LNG markets. 

Section 5 Increasing Interdependence 

 Among Energy Markets
2006

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2006

Key areas of integration 

• Natural gas and electric markets. Natural gas is a 

major fuel for the electric industry, and natural gas 

prices often set electric power prices because gas-fired 

plants are the marginal units in many areas. Further, 

reliability during stressful periods requires strong 

integration between the market operations of the two 

industries. 

• Natural gas and oil markets. Despite the fact that 

regional natural gas prices moved below competing fuel 

oil prices in some regions and decreased the demand 

for oil, high global oil prices may be preventing U.S. 

natural gas prices from dropping further. Changing 

dynamics in international fuel markets, however, 

may alter the traditional oil-natural gas pricing 

relationships. 

• Global LNG markets. In 2006, imports of LNG into 

North America fell, as LNG moved from the Atlantic 

Basin to more attractive markets in India and East 

Asia. This trend expands competition for global 

natural gas beyond that observed between Europe and 

North America in previous reports.45 Indeed, global 

LNG markets may be surpassing oil in influence on 

U.S. natural gas markets.

45. Federal Energy Regulatory Commission (FERC), 2004 State of the Markets Report (Washington, DC: 2005) (2004 SOM).

46. EIA, Monthly Flash Estimates of Electric Power Data, “Table 5.1 Trends in Fossil Fuel Consumption for Electric Generation, Total (All Sectors),” Jan. 19, 2007.

 

Natural Gas and Electric Markets

Power generators used 19.2 Bcf of natural gas per day 

through November 2006, up 6.2 percent from 2005.46

Estimates of daily natural gas deliveries to power 

generators peaked on August 2, 2006, at nearly 42 Bcf – 

31 percent more than the 2005 peak of 32 Bcf on August 

3, 2005 (see Figure 21).

Importance of Coordination in Electric 

and Gas Operations

Given the importance of natural gas in electric generation 

– in terms of its size and its role as a marginal electric 

fuel – integration of market operations between the two 

industries becomes critical during periods of system stress. 

2005

2006

MMBtu per Day

Estimated Natural Gas Delivered to U.S. 

Power Plants, 2005-06

Fig 21

Source: Derived from Bentek Energy, Supply/Demand Balance data.

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

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

Estimated Natural Gas Delivered to U.S. Power 

Plants, 2005-06

Fig 21

Source: Derived from Bentek Energy, Supply/Demand Balance data.
2006

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2006

Three incidents, two from 2004 and one in 2006, illustrate 

the point:

• New England (January 2004). Sustained record cold 

weather hit New England and eastern Canada from 

January 14 through January 17, 2004.47 Intraday gas 

prices reached $75/MMBtu. Some gas-fired generators 

sold their natural gas – instead of using it to fuel power 

generation – and then declared economic outages, 

leading to a reserves shortage and almost to a blackout. 

Differences in power and gas scheduling created 

uncertainty for generators about relative prices. 

• San Diego Gas and Electric (November 2004). On 

November 19, 2004, Unit 2 (1,122 MW) at the San 

Onofre Nuclear Generating Station in California 

unexpectedly tripped (or became unavailable). Unit 3 

was already unavailable.48 The reduced electric supply 

increased demand for natural gas generation in the 

San Diego area, straining San Diego Gas and Electric’s 

(SDG&E) gas distribution capabilities. The situation 

was further exacerbated when, on November 22, 2004, 

a control valve slammed shut on one of SDG&E’s main 

gas supply lines and further reduced the pressure on the 

line. When the weather also turned cold, increased gas 

demand in SDG&E almost forced curtailment of electric 

generation, which could have led to rolling blackouts. 

Indeed, California may have the most dramatic need 

for coordination between electric and gas markets since 

that state’s stringent air quality restrictions effectively 

eliminate potential fuel switching to oil when natural gas 

supplies are low.

• Public Service Company of Colorado (February 2006). 

On February 18, 2006, Public Service Company of 

Colorado (PSCo) imposed a rolling blackout affecting 

300,000 customers between 8:48 a.m. and 10:18 a.m. 

Temperatures fell as low as minus-13 degrees Fahrenheit, 

15 degrees colder than forecasted. Heating demand for 

gas coupled with growing electric needs exceeded the gas 

supplies PSCo had nominated, reducing line pressure on 

PSCo’s gas distribution system and shutting down some 

gas-fired plants.49 

ISO-NE’s response to its 2004 incident was an important first 

initiative in addressing electric/gas coordination issues. ISONE fostered better communications with interstate natural 

gas pipelines and generators about operating conditions and 

devised new cold weather operating procedures. It developed 

better information about the ability of units to respond to 

emergency conditions and relaxed its $1,000/MWh offer 

price cap during emergencies to permit generators to recover 

higher gas costs. 

ISO-NE’s improved coordination has helped harmonize 

scheduling and pricing between the natural gas and electric 

industries in New England. Deadlines for day-ahead offers 

and subsequent scheduling confirmations vary significantly 

among the RTOs (see Table 10). 

47. 2004 SOM, p. 13-24.

48. San Onofre Unit 3 was unavailable due to refueling. San Onofre Unit 1 was permanently shut in 1992 for decommissioning. 

49. Investigation of Controlled Outages of Feb. 18, 2006, by the Public Service of Colorado, Docket No. 06I-118E6, Colorado Public Service Commission, Jul. 7, 2006. 

 RTO Day-Ahead Notification Notes

 Offers Due

ISO-NE Noon Re-offer between

4:00 to 6:00 p.m.

MISO 11:00 a.m. 4:00 p.m. 

 

NYISO 5:00 a.m. 11:00 a.m.

PJM Noon 4:00 p.m. 

SPP N/A* N/A 

ERCOT N/A* N/A 

CAISO N/A* N/A 

* No day-ahead market

Source: Staff analysis of RTO rules.

ISO-NE may invoke “Cold 

Weather Event” and move 

day-ahead offer deadline 

to 9:00 a.m. 

Re-offers accepted from 

4:00 to 5:00 p.m. 

No re-offer or emergency

provisions (about 95% of 

market clears day-ahead)

Re-offer between 4:00 

and 6:00 p.m. 

N/A

N/A

N/A

Table 10: Timeline for Day-Ahead Power 

Offers by RTOs in 2006
2006

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FEDERAL ENERGY REGULATORY COMMISSION

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By contrast, time windows for buying day-ahead physical 

natural gas are similar across the country. Most market 

participants buy physical natural gas between 9:00 and 

11:00 a.m. the day before the natural gas fl ows. The relative 

uniformity resulted from several years of collaboration by gas 

industry market participants to craft standards (promulgated 

by the North American Energy Standards Board and its 

predecessor, the Gas Industry Standards Board) to implement 

the nominations and scheduling aspects of FERC Order Nos. 

636 and 637. Interstate (and often intrastate) pipeline tariffs 

now incorporate these standards by reference. 

The Commission’s Response

The Commission responded to the power scheduling 

uncertainties on October 25, 2006, stating that the: 

Commission is concerned that the scheduling practices 

of independent system operators (ISOs) and regional 

transmission organizations (RTOs) are not effectively 

coordinated with the scheduling of natural gas purchase 

and transportation transactions, so that gas-fi red must-run 

generators may be unable to obtain gas during periods when 

gas transportation is constrained or gas prices are volatile. 

To address these issues, the Commission will institute 

inquiries pursuant to section 206 of the Federal Power Act 

(FPA) in the above referenced dockets to provide the parties 

in ISOs and RTOs with forums in which to examine whether 

scheduling and compensation mechanisms need to be revised 

to ensure that gas-fi red generators can obtain gas when the 

gas-fi red generation is necessary for reliability and that they 

are compensated appropriately when volatility in gas prices 

creates diffi culty in recovering gas costs. Each of the RTOs 

and ISOs above must make a fi ling by January 16, 2007, 

either proposing necessary changes to their scheduling and 

compensation systems or explaining why such changes are 

unnecessary.50

Also on October 25, 2006, the Commission issued a Notice of 

Proposed Rulemaking to incorporate by reference proposals 

to add another intraday gas cycle with bumping rights, 

change energy timelines in RTOs so that electric markets can 

clear within existing gas nomination periods, and require 

generators that bid into day-ahead markets to have enough 

gas to run if called.51

Natural Gas and Oil Markets

In recent years, natural gas prices have depended 

largely on storage levels and the world price of oil (see 

Figure 22), in addition to weather and development and 

exploration costs. The ratio of natural gas prices to 

oil prices can change based on storage levels, with gas 

prices rising compared to oil when storage levels are low. 

The results since 2001 show that relatively low storage 

levels correspond with high gas prices. When storage 

inventories are high, however, gas prices fall compared 

to oil to a level that looks fairly consistent over time. In 

effect, it appears that gas prices do not fall much further 

than to a ratio of about 0.43 to oil prices (with both priced 

on a common Btu basis), a level that has been much in 

evidence in late 2006. Conversely, in times of shortage, 

the ratio of natural gas to oil prices rarely exceeds 2.0.52

More specifi cally, the results of 2005 and 2006 show 

that:

• Natural gas prices have risen quite high when market 

participants are unusually fearful about the adequacy of 

natural gas supplies. Gas prices for the post-hurricane 

period in 2005 were consistently higher than previous 

experience with similar storage levels would have 

50. Order Instituting Inquiries into Gas-Electric Coordination Issues, 117 FERC ¶ 61,094 (2006), 1.

51. Standards for Business Practices for Interstate Natural Gas Pipelines and Standards for Business Practices for Public Utilities, Notice of Proposed Rulemaking, 117 FERC ¶ 

61,095 (2006).

52. The weekly deviation from average storage inventories on the X axis of Figure 22 is based on the average of storage inventories from 2001 to 2005, rather than 2006, 

which was an atypical year.
2006

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FEDERAL ENERGY REGULATORY COMMISSION

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suggested. The unusually high prices 

refl ected the fear of many gas customers 

that a cold winter and lower production 

levels could lead to shortages. Local 

distribution companies that hedged 

their positions at unusually high prices 

appeared to be acting sensibly under 

the circumstances – they could not have 

known that January 2006 would be the 

warmest on record and that husbanding of 

gas supplies would prove unnecessary.53

• World oil prices tended to support 

natural gas prices despite record levels of 

storage. During 2006, gas storage levels 

were much higher than in recent years, 

but overall gas prices remained about the 

same compared to oil as in other years. 

In effect, world oil prices appear to have 

prevented North American gas prices from 

falling further. This dynamic may refl ect a 

global connection between natural gas and 

petroleum prices that affects the United 

States even where LNG is a small part of 

overall supply. 

Competition with Residual Fuel Oil 

in Some Markets

Although world oil prices apparently prevented 

a steeper drop in U.S. natural gas prices, gas 

prices did drop enough that natural gas could 

and did displace residual fuel oil in certain 

markets. For example, for several years, natural 

gas prices in the Northeast have ranged between 

a fl oor set by residual (No. 6) fuel oil prices and 

a ceiling set by distillate (No. 2) fuel oil prices, 

0.0

0.5

1.0

1.5

2.0

2.5

-1,000 -500 0 500 1,000

Weekly Deviation from Average Storage Inventories (Bcf) 

1994 through pre-Katrina 2005

Post-Katrina through year-end 2005 

"Base" ratio of 0.43

Ratio of Nymex Gas-to-Oil Prices 

2006

Ratios of Oil and Gas Prices Versus Storage Levels, 1994-2006

Fig 22

Source: Staff analysis of EIA Weekly Natural Gas Storage Report and Nymex data.

53. In fact, it is critical that local distribution companies in early winter protect storage inventories and rely more heavily on spot gas – even if the prices are unattractive. 

Storage functions as a vital insurance policy for U.S. energy markets through the winter. Interestingly this crucial behavior is, in effect, indistinguishable from speculators 

buying in a tight market in the hope of higher prices, and necessarily has the same effect on overall market prices.

$0

$4

$8

$12

$16

Lower bound range reflects 

low sulfur (0.3%) No. 6 residual 

fuel oil in NYC

Upper bound 

range reflects 

No. 2 distillate 

oil in NYC

Blue line 

indicates 

spot gas 

price 

at Transco 

Zone 6 NY

Delivered gas prices were 

cheaper than residual fuel 

oil prices in NYC throughout 

most of the summer

2002 2003 2004 2005 2006

Price ($/MMBtu) 

 Gas and Fuel Oil Prices in New York City, 2002-06

Fig 23

Source: Derived from Bloomberg data. 

Ratios of Oil and Gas Prices Versus Storage Levels, 1994-2006

Fig 22

Source: Staff analysis of EIA Weekly Natural Gas Storage Report and Nymex data. 

 Gas and Fuel Oil Prices in New York City, 2002-06

Fig 23

Source: Derived from Bloomberg data. 
2006

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FEDERAL ENERGY REGULATORY COMMISSION

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except during brief weather-driven price increases (see 

Figure 23). Beginning in March 2006, the price of delivered 

natural gas in New York fell below that of competing low 

sulfur residual fuel oil and remained there for many months. 

The last time natural gas prices fell below those of residual 

fuel oil for a signifi cant period in the Northeast was in 2002. 

In 2006, the natural gas price fell further below the residual 

fuel oil price for a longer time. 

The low natural gas price compared to fuel oil strongly 

affected fuel use. Through October 2006, EIA reported, the 

electric power sector burned less than half as much oil as in 

2005, while gas usage rose about 5 percent.54

More competitive gas prices affected generation fuel mixes 

most in Florida, New York, and New England. In Florida, 

gas use grew signifi cantly during summer 2006 (see Figure 

24). Florida accounts for about 25 percent, or 246 MMcfd, 

of the estimated average monthly dual-fuel residual plant 

capability in the United States.55

Global LNG Markets

Global LNG supplies are crucial to the energy future of the 

United States. Economic growth, increasing use of natural 

gas for electric power generation and the growing use of 

natural gas for oil recovery in Canada will all add extra 

demand that domestic supply is unlikely to meet. As a 

result, increased capability to import LNG remains a central 

part of the country’s ability to address its energy challenges. 

Planned investment in new LNG terminal capacity continued 

during 2006 as market participants continued to see the 

importance of increased imports in the future.

In the short term, LNG deliveries declined somewhat in both 

2005 and 2006 for reasons that were peculiar to the two 

years. In 2005, the decrease was partly due to the logistical 

problems of delivering LNG in the wake of the hurricanes. 

Deliveries to Lake Charles, Louisiana, were down by 60 Bcf, 

while deliveries to other terminals increased by 39 Bcf. In 

2006, the mild winter and storage overhang reduced relative 

U.S. prices and consequently the immediate demand for 

LNG. 

In addition, the experience of 2005 and 2006 made clear that 

LNG markets are global, with increasing activity in Asia as 

well as Europe. 

Imports Down in 2006

In 2006, North America saw an unusual combination of a 

warm winter, high storage inventories and falling natural 

gas prices. As a result, LNG imports into the United States 

fell by 8 percent, or 49 Bcf, in 2006,57 after falling 3 percent, 

or 21 Bcf, in 2005 (see Table 11). Rising 2006 imports to 

terminals at Lake Charles, Louisiana; Elba Island, Georgia; 

and Everett, Massachusetts, did not fully offset a 105 Bcf 

decline at Cove Point, Maryland.

54. EIA, Monthly Flash Estimates of Electric Power Data, Dec. 21, 2006.

55. Kenneth L. Yeasting for CERA, Dual Fuel Steam Generation: Alive and Well, Nov. 20, 2006.

56. Florida gas deliveries refl ect scheduled, intra-day 2 natural gas volumes on Gulfstream Natural Gas System at Station 100 and at Florida Gas Transmission Compressor 

Station 11 at Mount Vernon. 

57. Final 2006 import totals by terminal were not published as of this writing; 2006 values are estimates.

Daily Natural Gas Deliveries to 

Florida Power Plants 2005-06

Fig 24

0

5,00

1,000

1,500

2,000

2,500

3,000

3,500

2006

2005

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

MMcfd

Source: Derived from Bentek Energy data.

Daily Natural Gas Deliveries to Florida 

Power Plants 2005-06

Fig 24

Source: Derived from Bentek Energy data.
2006

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2004 2005 2006 Change % Change % Change % Change

Table 11: Annual U.S. LNG Imports by Terminal, 2004-06 (Bcf)

Cove Point 209 222 116 12 6% -106 -48%

Elba Island 105 132 146 27 26% 14 11%

Energy Bridge 0 5 0 5 N/A -5 -91%

Everett 174 169 176 (5) -3% 7 4%

Lake Charles 164 104 144 (60) -37% 40 39%

Total 652 631 582 (21) -3% -49 -8%

Source: Derived from EIA U.S. Natural Gas Imports by Country, and The U.S. Waterborne LNG Report data.

 2005-2004 2006-2005 

2006

FEDERAL ENERGY REGULATORY COMMISSION

Investment Remains Strong

The recent declines in LNG imports are likely to be temporary. 

Over the long term, falling natural gas production and 

increasing natural gas demand in North America will require 

increased reliance on imported LNG. Interest in developing 

LNG infrastructure in North America remains strong. Key 

developments in 2006 included:

• Excelerate Energy and Suez LNG have both received 

the approval of the governor of Massachusetts to site 

two terminals with capacities of 800 MMcfd and 750 

MMcfd, respectively, in the waters offshore of Boston; 

state environmental permits are pending. In addition, 

the Suez LNG proposal received a federal deepwater port 

license from the U.S. Maritimes Administration.

• Canaport, sponsored by Repsol and Irving Oil, obtained 

project fi nancing in October for a regasifi cation plant 

to interconnect with the Maritimes & Northeast Pipeline 

in New Brunswick and serve the northeastern United 

States. The imports would replace lower-than-expected 

offshore production from Sable Island. 

• Energía Costa Azul, Sempra’s Baja California project, is 

more than 67% complete. Commercial operations are 

set to begin in early 2008 with an initial capacity of 1 

Bcfd.58

Competition with Europe

In 2006, Europe remained the primary alternative to the 

United States for deliveries of Atlantic Basin LNG. European 

gas markets had relatively few liquid, or greatly used, pricing 

points – the key ones were the National Balancing Point (NBP) 

in the United Kingdom and Zeebrugge in Belgium. Prices at 

NBP and Zeebrugge tended to track each other because of 

a direct pipeline connection between the two. Both points 

showed lower prices than in other European markets, such 

as Spain, where many LNG prices were linked to oil prices 

or buyers who were willing to pay almost any price for LNG 

because they could average these costs with cheaper supplies 

into the rates they charge their customers.

NBP prices have tended to be higher than Henry Hub in the 

winter and similar or lower in the summer, partly refl ecting 

the scarcity of storage in Western Europe. However, when 

Henry Hub prices increased in fall 2005 because of hurricanes 

Katrina and Rita, they reached much higher levels than at 

NBP (see Figure 25). 

NBP prices also show two signifi cant dips in 2006 due to 

the opening of new pipeline connections. In some cases, 

intraday prices actually went negative when the Langeled 

Pipeline connected the United Kingdom to Norwegian gas 

supplies via the Sleipner riser facility. 

58. Dale Kelly-Cochrane for Sempra LNG, Energia Costa Azul LNG Terminal & Pipeline Status Report, [California] Governor’s LNG Task Force Briefi ng, Jan. 18, 2007.
2006

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During 2005 and 2006, deliveries to Lake Charles responded 

to major price disparities between Europe and North America 

when it was physically feasible to do so. Lake Charles 

imports dropped to (or remained at) very low levels on the 

three occasions when European prices rose far above Henry 

Hub prices. On the one occasion when Henry Hub prices 

were noticeably higher than European prices, imports into 

Louisiana were diffi cult because of hurricane damage and, 

thus, import volumes did not rise signifi cantly. 

Increased Deliveries to Asia 

A key development in 2006 in global natural gas markets 

was the increased importance of Asian purchasers for 

Atlantic Basin LNG (see Figure 26). Market participants sold 

about 112 Bcf of spot LNG from Egypt, Algeria, Nigeria, and 

Trinidad, or “west of Suez,” to customers in the Far East 

from April through December 2006.59 They sold almost no 

such gas before 2006.60

Floating Storage

Competitive markets – increasingly including global LNG 

spot markets – innovate where necessary. The LNG industry 

depends on three capital intensive types of investment: 

liquefaction facilities in producing countries, LNG tankers, 

and plants that regasify in receiving countries. At any time, 

the three investment streams are likely to be somewhat out 

of phase with each other. During 2006, for example, there 

was a relative glut of tankers compared to liquefaction 

capacity.61

59. The U.S. Waterborne LNG Report, Dec. 20, 2006.

60. Staff telephone call with Steve Johnson, Waterborne Energy, Dec. 21, 2006.

61. Ibid.

 LNG Imports Respond to U.S. and UK Price Differences, 2005-06

Fig 25

Source: Derived from Bloomberg; DOE, Natural Gas Imports and Exports,DOE, LNG Imports: Monthly Report; and The U.S. Waterborne LNG Report data. Price Difference ($/MMBtu)

0

1

2

3

4

5

6

7

8

9

10

Bcf

Average Weekly Imports at Lake Charles in Bcf Average Weekly Difference Between Henry Hub and 

National Balancing Point (UK) Spot Prices ($/MMBtu)

 2005

J FMAM J A S O ND JMAM J J AO ND

 2006

($20)

($15)

($10)

($5)

$0

$5

$10

LNG Imports Respond to U.S. and UK Price Differences, 2005-06

Fig 25

Source: Derived from Bloomberg; DOE, Natural Gas Imports and Exports, DOE, LNG Imports: Monthly Report; and The U.S. Waterborne LNG Report data.
2006

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Atlantic Basin LNG Sold to Asian Buyers,

April-December 2006 

Fig 26

Source: Derived from The U.S. Waterborne LNG Report data.

Apr May Jun July Aug Sept Oct Nov Dec

Taiwan

Korea

Japan

India

0

5

10

15

20

25

30

Bcf

62. The U.S. Waterborne LNG Report, Dec. 20, 2006.

 

Market participants responded to this imbalance by creating 

so-called fl oating storage. Shippers took advantage of large 

seasonal differences in summer and winter gas prices (winter 

gas was greater than $4/MMBtu more than summer gas at 

Henry Hub) by holding LNG for several months in at least 

16 tankers. These ships discharged up to 45 Bcf of gas, some 

purchased as early as June 2006, in November and December. 

One company (Excelerate Energy) devised a way to transfer 

LNG from ship to ship, allowing it to consolidate cargoes to 

minimize the gas that evaporates from each tanker. 

Of the 16 tankers waiting in mid-ocean in the middle of 

November, 13 discharged loads by mid-December:

• Six to Asia, India and the Far East;

• Three to Europe: two to Spain and one to Zeebrugge;

• Four to North America: two to Lake Charles, one to Elba 

Island and one to Altamira; and 

• As of late December, three were still at sea: one off Malta, 

one in the Caribbean, and one off South Asia.62

Atlantic Basin LNG Sold to Asian Buyers, 

April-December 2006 

Fig 26

Source: Derived from The U.S. Waterborne LNG Report data.
2006

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Section 6 Demand Response in Summer 2006

Demand response played a key role in meeting peak needs across 

the United States during stressful periods in summer 2006. 

In two of the most electrically vulnerable areas of the United 

States – Long Island and southwest Connecticut – demand 

response appeared to have reduced peak load by signifi cant 

amounts, as much as 4.6 percent and 6.1 percent of peak load, 

respectively. In these areas, demand response may have made a 

decisive contribution to avoiding blackouts.
2006

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Demand response

Demand response63 as practiced in today’s RTO markets 

consists of many separate programs, including:

• Reliability-based programs that include both voluntary 

emergency programs that compensate respondents 

when they curtail during an emergency and capacity 

programs that curtail customers in exchange for a 

payment or rate discount;

• Economic programs that allow participants to submit 

load reduction bids into day-ahead and real-time 

markets;

• Time-based rates, such as time-of-use rates and realtime pricing;

• Legacy utility programs, such as interruptible tariffs or 

direct load control that contribute to system reliability; 

and

• Calls for voluntary conservation without direct 

economic benefi t to the customer.

These programs formed a patchwork of initiatives to 

reduce system loads at peaks. They had different sponsors 

– state governments, utilities, and the RTOs themselves. 

Demand-response programs had different rules and 

rationales, depended on different payment mechanisms, 

and appealed to different customer motivations. Most 

had little or no direct connection to spot market forces. 

Nonetheless, in aggregate during summer 2006, they 

delivered benefi ts by reducing demand on the system at 

the times of most stress. 

Connecticut provides a good example of how demand 

response worked in summer 2006. Reliability-based realtime interruptible resources comprising four programs 

and four resource types were called on to reduce the peak 

load on the peak day of August 2, 2006 (see Figure 27). 

Demand resources appeared to eliminate demand growth 

through the afternoon of that day, a time when demand 

would normally grow considerably. Demand response 

appeared to produce similar patterns in all of the eastern 

RTOs. 

Reliability Based resources: Load reduction; Distributed generation: 

customer sited generation; Emergency generation: backup 

generators with permits to run in limited circumstances; Load 

Reduction & Emergency Generation: facilities using a combination 

of load reduction and emergency generators.

ISO-NE Actions. Emergency Procedure 1 (OP-4, Action 9): reserve 

shortage conditions; interrupt 30-minute demand resources that do 

not require voltage reduction. These customers have guaranteed 

they will respond, and receive capacity payments; Emergency 

Procedure 2 (OP-4, Action 12): Further actions to maintain 10-

minute reserve; interrupt 30-minute demand resources that require 

a voltage reduction. 

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FEDERAL ENERGY REGULATORY COMMISSION

63. Demand response usually refers both to reductions or interruptions in load as well as to the use of generating units that are on a customer’s site – distributed generation. 

Both reduce the stress on grid resources. 

6,700

6,900

7,100

7,300

7,500

7,700

11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00

Hour Ending

MWh

Anticipated

Load

Emergency 

Procedure 1

Emergency 

Procedure 2 Emergency 

Procedure 1

Canceled

Emergency 

Procedure 2

Canceled

Load Reduction & Emergency Generation

Emergency Generation

Distributed Generation

Load Reduction

Demand Response Lowers Connecticut Load on 

Peak Day

Fig 27

Source: Derived from preliminary ISO-NE data.

Demand Response Lowers Connecticut Load 

on Peak Day

Fig 27

Source: Derived from preliminary ISO-NE data. 
2006

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The variety of demand-response programs made it hard 

to measure their effects on system peak in aggregate. 

Nevertheless, the best estimates from the RTOs all showed 

demand reductions associated with demand response in 

each region on or near peak-demand days in 2006 (see 

Table 12). 

Price effects differed among the RTOs. MISO estimated 

that demand response lowered prices by $100-$200/

MWh.64 PJM estimated the price reduction to be $300/

MWh.65 In New England, by contrast, demand-response 

programs had no price effect because they were dispatched 

only when scarcity pricing also was in effect; scarcity 

pricing in New England sets the relevant prices at $1,000/

MWh. In New York, the interaction of demand response 

and demand-curve driven scarcity pricing was diffi cult to 

assess. Reliability-based demand response in New York 

can set the market price when dispatched, and is part of 

NYISO scarcity pricing procedures. 

Demand Response and Markets

Most demand-response programs in RTO regions during 

summer 2006 had little or no direct connection to the 

operation of RTO markets and market-clearing price 

formation. Some – voluntary reductions – amounted to a 

willingness on the part of customers to reduce demand for 

no payment. Other customers curtailed their consumption 

when directed by system operators. These customers were 

either under interruptible rates that provide rate discounts in 

exchange for a customer’s obligation to curtail, or capacity 

programs that provide a guaranteed payment (typically based 

on prevailing capacity market prices) to customers who 

curtail when directed. These programs represent an option 

the customer had previously sold prior to the real-time 

market, and are generally set by various forms of regulation, 

not by market forces. 

Though impossible to separate the effects, most utilities 

and RTOs invoked demand-response programs to preserve 

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FEDERAL ENERGY REGULATORY COMMISSION

RTO/Region Peak Day Peak Day Demand Response Price Effect

Table 12: Demand Response Effects in RTOs on Peak-Demand Days, Summer 2006

ISO-NE August 2 28,127 496 1.7% None

 SW CT August 2 3,701 227 6.1% 

NYISO August 2 33,879 1,139 3.5% Unknown

 NYC August 2 11,347 429 3.8% 

 Long Island August 2 5,684 261 4.6% 

PJM August 2 145,951 N/A 1.4% $300

 Mid-Atlantic August 2 62,017 2,050 3.3% 

MISO* July 31 136,250 1,096 0.9% $100-200

CAISO July 24 50,270 2,066 4.1% Unknown

Date (MW) (MW) % of Peak (est. $/MWh)

* MISO’s peak demand response occurred on August 1, though the peak load was on July 31.

Source: Derived from preliminary RTO data.

64. Phone interview between OE staff and the Midwest Independent System Operator.

65. PJM news release, Aug. 17, 2006, and phone interview between OE staff and Andy Ott, PJM vice president of markets, August 2006.
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reliability, not to affect markets.66 As a result, some observers 

interpreted the resulting demand response as being unrelated 

to markets. 

For example, MISO’s independent market monitor reported 

that invoking emergency measures reduced demand enough 

to prevent the imposition of scarcity pricing.67 In his 

view, demand response “had the effect of depressing the 

price signals that should occur during shortage and nearshortage conditions.”68 More than two-thirds of the demand 

response came from interruptible load, for which customers 

had already received lower rates, and responses to appeals 

for conservation, in which customers responded even with a 

direct price of effectively zero.69 

Specifi c RTO Experiences

Specifi c information available about demand response differs 

from region to region. Among the highlights:

ISO-NE. ISO-NE called for demand response on two days, 

but activated all reliability programs only on August 2.70

Almost half of all demand response reported by ISO-NE 

came from southwest Connecticut, the most constrained 

area. About 75 percent came from Connecticut as a whole. 

Much of the rest came from Maine, the least constrained 

area. ISO-NE demand response appeared to be about equally 

split between load reduction and emergency or distributed 

generation.

NYISO. NYISO called on demand-response resources on 

fi ve days, July 18-19 and August 1-3.71 On the peak day, 

August 2, demand reduction totaled 1,189 MW statewide.72

Demand response from economic programs was small where 

it mattered most – New York City and Long Island programs 

account for only 15 MW.73 On August 2, NYISO exported 

1,300 MW of emergency energy to New England during one 

key afternoon hour and called on resources in western New 

York zones to provide voltage support for sales to PJM.74

The PJM sales would not have been possible without demand 

response.75

PJM. PJM invoked its “Full Emergency Load Response” 

programs on August 2 and 3, but not its Energy Only 

(voluntary economic) program; some load-serving entities 

2006

FEDERAL ENERGY REGULATORY COMMISSION

66. CAISO directed California investor-owned utilities to activate their interruptible programs and reduce load only on the third peak day; based on CAISO peak day conference 

calls with Commission Staff (including California IOUs, municipal utilities, the Governor’s Offi ce, and other state agencies), July 24 and 25, 2006. MISO, “Midwest ISO 2006 

Load Management Response Survey, Summary, Jan. 5, 2007,” and “Summer 2006 Review: Presentation to the Midwest ISO Board of Directors – Markets Committee,” Sept. 

20, 2006. PJM: Email correspondence between Craig Glazer, PJM Interconnection, and Commission Staff, Sept. 13, 2006. NYISO, NYISO 2006 Demand Response Programs, 

semiannual demand response report to the Commission, Jan. 16, 2007. A notable exception was the Aug. 2 activation of the Emergency Demand Response Program (EDRP) 

and Special Case Resources (SCR) in three western New York zones to support scheduled market sales to PJM; on the same day, 1,300 MW of emergency energy was sold to 

ISO-NE, which was in a 5% voltage reduction state (p. 11). ISO-NE: “New England Demand Response: Summer 2006,” September 2006.

67. David B. Patton, “Independent Market Monitor Review: 2006 Peak Load Event,” PowerPoint presentation to the Markets Committee, MISO Board of Directors, Sept. 20, 2006.

68. Patton, Sept. 30, 2006, 3.

69. The Midwest ISO “2006 Load Management Response Survey, Jan. 5, 2007 Summary” (emailed to staff) reported that on Aug. 1, total demand reduction was 2,651 MW. The 

three largest contributing categories were: interruptible loads (1,387 MW or 52%), public appeals (465 MW, 17.5%), and behind-the-meter generation (375 MW, 14%).

70. “New England Demand Response: Summer 2006,” September 2006.

71. NYISO, “Operations and Market Performance: Summer 2006,” draft for discussion (Power Point presentation prepared for monthly staff conference call on Sept. 13, 2006).

72. NYISO, “Operations and Market Performance.” A subsequent call between Commission and NYISO staff (Dec. 14, 2006) made it clear that calculating actual responses is 

complicated by delays in data submission as well as the Customer Base Line (CBL) methodology used to compute the reductions. More detailed information was in the 

NYISO 2006 Demand Response Programs, semiannual demand response report to the Commission, Jan. 16, 2007, 13-14.

73. David J. Lawrence, “NYISO’s Demand Response Programs,” PowerPoint presentation at New York Market Orientation Course (NYMOC), November 2006.

74. Monthly conference call between Commission and NYISO staff, Aug. 2, 2006.

75. Ibid.
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(LSEs) invoked local programs more widely.76 PJM 

estimated that almost half of the overall reduction came 

from LSE programs in the Mid-Atlantic control area.77 PJM 

also estimated total savings to the system of $650 million 

for the week, of which $230 million was saved on August 2 

alone.78

MISO. MISO invoked emergency measures between July 31 

and August 2,79 and many Midwestern utilities invoked their 

own demand-response programs during the heat wave.80

MISO does not operate reliability-based or economic 

demand-response programs as do other ISOs.81 Its estimates 

of demand response were therefore uncertain, prompting 

it to undertake a survey of its demand resources, sent to 

balancing authorities and utilities.82

CAISO. During the time of system peak, California relied on a 

combination of reliability-based demand response programs 

operated by utilities and voluntary load curtailments. 

California relied heavily on voluntary load reductions, 

augmented by the governor’s call for a 25 percent reduction 

in power use at state agencies, none of which compensates 

customers for curtailing use.83 CAISO estimated initially that 

conservation cut demand by about 1,500 MW daily during 

their heat wave, during which the peak day occurred.84

CAISO asked utilities to activate interruptible load programs 

only once, on July 24, the peak day.85 Demand reductions 

were also achieved from the Demand Reserves Partnership, 

a program that allows third-party participation and 

aggregation. 

2006

FEDERAL ENERGY REGULATORY COMMISSION

76. E-mail correspondence between PJM Interconnection staff (Craig Glazer and Susan Covino, Demand Response Manager) and Staff, Sept. 13, 2006, and subsequent phone 

conversations with PJM staff.

77. Ibid.

78. PJM news release, Aug. 17, 2006, and subsequent phone interview between OE staff and Andy Ott, PJM vice president of markets, August 2006.

79. Many facts on MISO-wide responses in this section are derived from “Independent Market Monitor Review: 2006 Peak Load Event,” presented to Board of Directors Markets 

Committee, by David B. Patton, Potomac Economics, Sept. 20, 2006, and “Midwest ISO Summer 2006 Review and Discussion,” Sept. 6, 2006, Carmel, Ind.

80. Multiple news reports during heat wave.

81. MISO, “The Current Role of Demand Response in Midwest ISO Spot Energy Markets,” Nov. 7, 2006, available at http://www.midwestmarket.org/publish/Document/3c9065_

10e9e96031d_-7f7a0a48324a?rev=1.

82. MISO, “Summer 2006 Review & Discussion,” Sept. 26, 2006; and “Midwest ISO 2006 Load Management Response Survey, Summary, Jan. 5, 2007,” e-mailed to staff.

83. A full accounting of the amount of demand response on July 24 in the CAISO has proven diffi cult. No agency or entity in California has summarized or cataloged the 

level of demand response from all sources. Some data are based on OE staff interviews with CAISO staff, Dec. 11-12, 2006. CAISO announced 18 days of “power watch” 

in 2006 compared to seven in 2005. A “power watch” is an alert posted on its Web site as a day-ahead warning that the ISO will need conservation on the following day, 

accompanied by a news release. Summary available at: http://www.caiso.com/docs/09003a6080/08/8a/09003a6080088aa7.xls. CAISO issued press releases calling for 

conservation on July 13, 17-18, 24-26; CAISO issued a press release touting conservation’s contribution, Aug. 1, 2006.

84. CAISO press releases, July through August 2006; staff interviews with CAISO, December 2006.

85. Staff monthly conference call with CAISO, Jul. 27, 2006, and Lawrence Berkeley National Laboratory analysis of CEC data fi led by utilities, e-mailed to staff, Dec. 11, 2006.
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North American futures and fi nancial energy markets continued 

to attract interest from investors in 2005 and 2006. Though no 

single measure of activity exists for futures and fi nancial energy 

trading, several measures document that overall activity increased. 

Of particular interest to observers of physical energy markets was 

an apparent increase in the interdependence of cash physical with 

futures and fi nancial markets. Additionally, futures and fi nancial 

energy markets came under greater scrutiny in 2006 as some 

public offi cials (in particular) expressed concern about the role of 

speculation in energy markets. 

Section 7 Growing Infl uence of Futures 

 and Financial Energy Markets
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Reports Raise Concerns About 

Energy Speculation

During 2006, three highly publicized reports argued that 

speculators drove North American natural gas prices 

higher than they would have been otherwise:

• The Midwest Attorneys General presented a study of 

natural gas prices in March that concluded, among 

other things, that customers were being “overcharged” 

$5 billion per month as a result of too-high gas prices.86

Commission staff raised signifi cant methodological 

concerns about the report.87

• The U.S. Senate’s permanent subcommittee on 

investigations, Committee on Homeland Security 

and Governmental Affairs, released a study in June 

that concluded, “The traditional forces of supply and 

demand cannot fully account for these increases [that 

is, in oil and gas prices from 2000 through 2006].”88

It also concluded that increasing futures prices due to 

speculation would raise spot prices.89

• The National Legal and Policy Center concluded 

in August that “high natural gas prices of the last 

fi ve years and current prices for natural gas futures 

likely refl ect other factors, including the structure 

of the market, speculation not based on economic 

fundamentals, and perhaps price manipulation.”90 It 

also concluded that “natural gas prices diverge from 

economic fundamentals even more in the futures 

market than in the spot markets.”91

The Role of Speculation

Despite the sometimes pejorative connotation of the term, 

speculation is a normal and necessary part of all markets. 

Speculation is the buying or selling of an interest in 

a commodity for the purpose of benefi ting from an 

expected (or hoped for) future value of that commodity. 

A robust market depends on a wide variety of confl icting 

perspectives about current and future market conditions 

to reach workably competitive levels. Otherwise, there 

is no basis for trading. For example, buyers and sellers 

would largely lose the benefi ts of hedging if there were 

no speculators willing to assume the risks that hedgers 

want to lay off. 

It is also important to note that the rising price of 

natural gas in North America was anything but unique, 

considering recent price trends and the possible role of 

speculation and other forms of investment in energy 

price movement. The United Nations reported that global 

prices for all basic commodities, including natural gas 

and petroleum, rose between 2001 and late 2005 largely 

because of global economic growth.92 One effect of 

such a commodity boom was to encourage the fl ow of 

fi nancial assets into commodity markets. Goldman Sachs 

estimated that investment in global commodities grew 

from less than $10 billion in 2001 to more than $50 billion 

in 2005, with about two-thirds of it in the Goldman Sachs 

Commodity Index fund (GSCI).93 The GSCI invested 10 

percent to 12 percent of its funds in natural gas and 56 

86. Mark N. Cooper, for the Midwest Attorneys General Natural Gas Working Group (Illinois, Iowa, Missouri, Wisconsin), The Role of Supply, Demand, and Financial 

Commodity Markets in the Natural Gas Price Spiral, March 2006, 6.

87. Transcript of Mar. 16, 2006 Commission meeting, 31-60, available at: http://www.ferc.gov/EventCalendar/Files/20060324072947-transcript.pdf.

88. U.S. Senate Permanent Subcommittee on Investigations, Committee on Homeland Security and Governmental Affairs, The Role of Market Speculation in Rising Oil and Gas 

Prices: A Need to Put the Cop Back on the Beat, Washington, D.C., Jun. 27, 2006, 1.

89. Ibid, 16, fn. 36.

90. Robert J. Shapiro and Nam D. Pham, An Analysis of Spot and Futures Prices for Natural Gas: The Roles of Economic Fundamentals, Market Structure, Speculation, and 

Manipulation, August 2006. Work conducted by Sonecon, LLC and supported by a grant from the National Legal and Policy Center, 1.

91. Ibid, 16.

92. United Nations Conference on Trade and Development, Trade and Development, 2006 (New York and Geneva, August 2006).

93. Goldman Sachs & Co., “The Goldman Sachs Commodity Index [GSCI]”, PowerPoint presentation of the GSCI New York Team and the GSCI London Team, May 2005, 3.
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percent to 64 percent in petroleum products (including 

crude oil) between 2003 and 2006.94

To illustrate why that consistent, sustained growth made 

sense to investors, the price of natural gas remained above 

its 200-day moving average most of the time for almost 

four years from early 2002 through late 2005 (see Figure 

28). Under those conditions, from the perspective of an 

investor (who, in this context would behave similarly to a 

speculator), buying a fi nancial interest in natural gas (as 

well as a variety of other basic commodities) proved a good 

investment over the whole period, regardless of any direct 

physical interest in the commodity itself. Those kinds 

of returns, particularly contrasted to returns available 

broadly in stock markets, clearly attracted investment 

capital. Goldman Sachs said that investors in the GSCI 

include “pension funds, foundations and endowments, 

high net worth individuals, insurance companies, asset 

managers, hedge funds, [and] private banks” in more than 

20 countries.95

Speculation and Other Price 

Movement Strategies

Though we tend to speak of speculation as if it were a single 

strategic approach to investment, it actually refl ects a broad 

array of strategies. Speculators in well-developed fi nancial 

energy markets can and do bet that almost every set of 

prices might go up or down, and different speculators bet 

in opposite directions for the same set of prices. Over the 

past few years, staff has noted apparent speculation in both 

directions in many cases.

Though not exactly the same as speculation, commodity 

index trading may play a similar role in futures and fi nancial 

markets. Investors include those, such as pension funds and 

individuals, who invest in the energy sector as part of an 

overall portfolio, without trading actively in the short term. 

In effect, over the past few years, these investors might have 

followed this logic: “Global growth is increasing demand for 

all sorts of commodities; I want to invest in a basket of such 

commodities in the expectation that their prices will rise.” 

Investment in the GSCI, for example, is commodity index 

trading.

By contrast, active speculation includes those that may 

trade actively in the short term, like many energy trading 

companies, investment banks, and hedge funds. In the case 

of hedge funds, falling natural gas prices apparently led to 

two major collapses in 2006:

• MotherRock, L.P., a $400 million energy hedge fund 

founded by former Nymex President Robert “Bo” Collins, 

failed at the end of July. After reporting 20 percent 

gains in 2005, MotherRock, which had borrowed money 

to increase its position in natural gas futures and overthe-counter swaps, lost all its own value and cost its 

prime broker, ABN-Amro, an estimated additional $60-

$100 million as natural gas prices fell.96

94. Goldman Sachs & Co., “Goldman Sachs Announces 2007 Weights for the Goldman Sachs Commodity Index”, press release, Nov. 6, 2006. Goldman Sachs anticipated 

lowering its weighting for natural gas in 2007 to less than 8%. Standard and Poors recently announced it would purchase the GSCI.

95. Goldman, Sachs & Co., “The GSCI,” p. 10.

96. “MotherRock Cries Uncle,” Aug. 3, 2006, www.thestreet.com; “Energy Hedge Fund Closes Shop,” Aug. 4, 2006, www.CNNMoney.com.

Henry Hub Spot Natural Gas Prices Relative to 

200-day Rolling Average, 2001-06

Fig 28

Source: Derived from Platts data. 

$0

$2

$4

$6

$8

$10

$12

$14

$16

$18

$20

2001 2002 2003 2004 2005 2006

Henry Hub Spot

200 Day Rolling Average

Price ($/MMBtu)

Henry Hub Spot Natural Gas Prices Relative to

200-day Rolling Average, 2001-06

Fig 28

Source: Derived from Platts data.
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97. “A Hedge Fund’s Loss Rattles Nerves,” Sept. 19, 2006 and “Hedge Fund Shifts to Salvage Mode; Amaranth Trying to Shed Gas Portfolio,” Sept. 20, 2006, by Gretchen 

Morgenson and Jenny Anderson, The New York Times; “Blue Flameout: How Giant Bets on Natural Gas Sank Brash Hedge-Fund Trader,” Ann Davis, Sept. 19, 2006, The Wall 

Street Journal; “Amaranth - How to Lose $5.0 Billion without Even Trying,” By Cal Payne, Sept. 25, 2006, IssueAlert@UtiliPoint.com.

• Amaranth Advisors, LLC, a multistrategy hedge fund, 

collapsed in September, suffering the largest loss ever 

by a hedge fund. Most reports say that Amaranth lost 

$5-$7 billion.97 Unlike MotherRock, Amaranth had 

enough investment to meet all of its margin calls, and 

it subsequently sold its energy portfolio to others. As a 

result, it posed no systemic credit risk to the markets.

 

Developments in Futures and 

Financial Energy Markets

Coinciding with increased capital infl ows, futures and 

fi nancial energy markets appeared to become signifi cantly 

more active in recent years. Together, futures and 

fi nancial energy markets comprise many venues, ranging 

from well-known, highly organized exchanges for 

standardized futures and options contracts on one end 

of the spectrum to a wide variety of much less standard, 

less well-understood bilateral agreements among active 

market participants on the other. As a result, there are no 

comprehensive measures of these types of energy market 

activity. Instead, observers must use the information that 

is available from various parts of the market as indicators 

of overall trends in the markets. Most available indicators 

come from the more standardized, transparent parts of 

the market. Less transparent parts of the market may 

well have grown more (or less) rapidly than the visible 

indicators suggest. 

Available indicators show that participants in the 

futures and fi nancial markets traded greater volumes, 

showed more willingness to hold on to sales or purchase 

commitments, and developed new ways to trade. Such 

markets also appeared to infl uence some cash physical 

markets. Increased activity was particularly apparent in 

visible natural gas markets, but affected electric power 

markets as well. 

Volume of Natural Gas Futures Traded 

Has Increased

Volumes traded for the Nymex natural gas futures contract 

– measured by the number of contracts bought and sold on 

any particular day – more than doubled over the past decade 

(see Figure 29). 

Willingness to Hold Gas Futures Positions 

(Open Interest) Increased More Rapidly

Nymex reports the overall willingness of its participants to 

hold positions to sell or buy futures using a measure called 

open interest. Open interest is the total number of futures 

contracts sold or bought (they total the same number) but 

not yet liquidated by offsetting transactions or delivered. 

Open interest rose much more rapidly than overall trading, 

especially since 2005 (see Figure 30). Specifi c changes in 

this measure indicate some important trends:

• Longer-term open interest grew, particularly for dates 

more than a year into the future. In effect, participants 

Daily Nymex Trading Volume 

Volume (thousands of contracts) 

Daily Average 28 Day 

Moving Average

Natural Gas Futures Contract Trading Volume 

Recovered to High Levels, 2006

Fig 29

Source: Derived from Nymex data. 

0

50

100

150

200

250

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006

Natural Gas Futures Contract Trading Volume 

Recovered to High Levels, 2006

Fig 29

Source: Derived from Nymex data.
2006

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became more willing to take positions further out in 

time. Increased activity in these longer-term markets 

could have been valuable for those who wanted to 

hedge periods longer than a year, as well as for those 

who wanted to speculate.

• Shorter-term open interest also grew substantially.

This growth underscores the overall success of the 

natural gas futures exchange in attracting activity, 

both speculative and hedging. Since fi nancial trading 

takes place in different markets than Nymex futures 

trading, the level of Nymex futures open interest 

inherently understates the collective activity in futures 

and fi nancial markets. With the growth of other related 

fi nancial instruments that use futures prices to set their 

value, and even sometimes directly mimic Nymex gas 

futures on other trading platforms, active participants 

can and apparently do develop much larger positions 

than are apparent on Nymex alone.

Electronic Trading of Nymex Gas Futures 

Now Competes with Pit Trading

Historically, futures trading occurred in a pit where designated 

trading representatives gathered and traded with each other. 

Nymex gas futures continue to use pit trading. Beginning 

on September 5, 2006, Nymex began simultaneous trading 

of its natural gas futures contract on the fl oor and using the 

electronic Globex system.98 Consequently, futures contracts 

now trade virtually around the clock, and the market 

is available electronically to traders all over the world. 

Electronic trading grew rapidly in late 2006 (see Figure 31), 

exceeding the volume of pit trading on October 30 for the 

fi rst time. 

98. After-hours trading (trading when the pit is closed) had taken place for many years.

Year 6

Year 5

Year 4

Year 3

Year 2

12

11

10

9

8

7

6

5

4

3

2

1 Month

Open Interest (thousands of contracts) 

 Natural Gas Open Interest Growth, 1997-2006

Fig 30

Source: Derived from Nymex data. 

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006

0

200

400

600

800

1,000

Natural Gas Open Interest Growth, 1997-2006

Fig 30

Source: Derived from Nymex data.
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99. 2004 SOM, 63. 

Trade Date

Natural gas pit contracts

Natural gas electronic contracts

Volume (thousands of contracts) 

Growth of Electronic Natural Gas Futures Trading Compared to Pit, 2006

Fig 31

Source: Derived from Nymex data. 

0

50

100

150

200

250

Jul Aug Sep Oct Nov Dec

Activity in Futures and Financial 

Electric Markets Also Increased

Nymex trading in electric futures has historically been less 

important than in natural gas. The electric power futures 

contract now centers on PJM (just as the gas contract centers 

on the Henry Hub) and has been in place since March 

19, 1999. Trading on the electric power futures contract 

increased 9 percent in 2006. 

As noted in the Commission’s 2004 State of the Markets 

Report, fi nancial trading of electric power on the 

IntercontinentalExchange (ICE) began to increase rapidly 

in 2004, especially in PJM.99 During 2005 and 2006, the 

increase in fi nancial electric swap trading continued (see 

Figure 32). The increases continued for electricity trading 

in PJM and were particularly notable at western trading 

hubs, where volume tripled between 2005 and 2006 (though 

starting from a lower base than PJM’s).

Infl uence of Futures Prices on Some 

Physical Gas Price Indices

As a practical matter, monthly cash physical and futures 

natural gas prices are and must be closely related to one 

another, if markets are working effectively. The fact that 

many participants can engage in both futures and monthly 

cash physical markets means that any material differences 

will be arbitraged away. That is, at least some market 

participants will pick the least expensive way to establish a 

position using different combinations of products. In doing 

so, they will force the values of those different combinations 

to converge. Consequently, big changes in cash physical 

market values naturally affect futures trading, and vice 

versa. 

However, in some cases, the mechanisms tying futures to 

monthly cash physical prices are more direct. Many natural 

gas market participants in many areas make contracts using 

Growth of Electronic Natural Gas Futures Trading Compared to Pit, 2006

Fig 31

Source: Derived from Nymex data. 
2006

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indices that rely on surveys of fi xed-price bilateral physical 

deals to set prices. For such contracts, the index price rests 

on an average of monthly cash physical deals made during 

the last fi ve business days of the prior month (known as 

bidweek) at fi xed prices that are then aggregated by the end 

of bidweek to form monthly price indices. 

By 2006, most of the transactions that set these indices in 

the Northeast United States and along the Gulf Coast were 

physical basis deals. But many of these physical basis deals 

set their price as the fi nal settlement price for the Nymex 

futures contract at Henry Hub plus a fi xed, agreed-upon 

differential. Consequently, in these locations, index prices 

are effectively an average of these fi xed, agreed-upon 

100. Monthly indices are only one part of overall market prices in any region. Large gas buyers such as local distribution companies (LDCs) typically buy some gas well in 

advance of use and put it in storage, and may buy monthly gas using a variety of fi xed and fl oating commodity prices. Furthermore, market-determined physical basis 

settles after the futures contract, and to some extent can change price in an opposite direction to the Nymex settle. Thus it is diffi cult to determine the actual fi nancial 

impact of the Nymex Henry Hub settle on any particular local market natural gas price.

GWh

 Growth of Financial Electricity Trading Volumes, 2003-06

Fig 32

PJM NYISO A

NYISO G NYISO J

NEPOOL Cinergy

SP15 NP15

Palo Verde Mid C

Source: Derived from ICE data. 

2003 2004 2005 2006

150,000

 0

50,000

100,000

200,000

250,000

300,000

differentials added to the fi nal Nymex settlement price. In 

those areas, index prices refl ect the Nymex close. 

The prevalence of physical basis transactions varied in 

indices varied around the country in 2006 (see Figure 33). 

Physical basis predominated in the Northeast and along the 

Gulf Coast but not in the rest of the country.100

The link between index prices used for physical contracts and 

the Nymex closing price is interesting because conventional 

wisdom sees the monthly cash physical markets as primary 

and the futures markets as derivative. The linkage from 

Nymex futures prices back to monthly cash physical 

prices and transactions occurs largely because market 

participants believe the Nymex trading market is reliable; as 

Growth of Financial Electricity Trading Volumes, 2003-06

Fig 32

Source: Derived from ICE data.
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Predominant (86-100%)

Majority (51-85%)

Some (16-50%)

Little or none (0 -15%)

 Use of Physical Basis in Natural Gas Price Indices at Major Trading points, 2006

Source: Staff analysis of Platts data. 

101. CFTC Commissioner Sharon Brown-Hruska, “The Functions of Derivative Markets and the Role of the Market Regulator,” address at 2006 Planalystics GasBuyer Client 

conference, May 18, 2006, available at: http://www.cftc.gov/opa/speeches06/opabrownhruska-45.htm.

former Commissioner of the Commodities Futures Trading 

Commission, Sharon Brown-Hruska, said: 

Gas buyers often utilize the Nymex monthly settlement 

prices to determine the prices for swaps and physical 

transactions. Both sides are willing to reference such a 

price because they believe that the price is determined in 

a liquid, effi cient and, importantly, transparent market.101

Provided that gas buyers and sellers are correct in their 

belief about the reliability of Nymex, the use of futures 

prices to effectively set some physical index prices is an 

understandable, if perhaps not well understood, practice.

101. CFTC Commissioner Sharon Brown-Hruska, “The Functions of Derivative Markets and the Role of the Market Regulator,” address at 2006 Planalystics GasBuyer Client 

conference, May 18, 2006, available at: http://www.cftc.gov/opa/speeches06/opabrownhruska-45.htm.

 Use of Physical Basis in Natural Gas Price Indices at Major Trading points, 2006

Fig 33

Source: Staff analysis of Platts data. 
2006

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Visit Us Online

For more information and discussion used to inform this report, please visit our Web site at www.ferc.gov/

oversight. At the site you will fi nd national and regional overviews of electric and natural gas markets as well 

as discussions of other related markets, including coal, oil, emissions allowances, LNG, and weather. Terms, 

acronyms and abbreviations used in this report are also included in a useful reference section located on the 

site.

The site is organized as follows:

State of the Markets: An overview that summarizes the key points of the natural gas and electric market 

content provided on this site.

Reports & Analyses: Reports that consider key issues affecting natural gas and electric markets.

Market Snapshots: Division of Energy Market Oversight presentations at the Commission’s Open Meetings.

Market Views: Collections of market information prepared for various audiences.

Electric Power Markets: An understanding of U.S. electricity markets.

Natural Gas Markets: An understanding of U.S. natural gas markets.

Other Markets: An understanding of the other U.S. energy markets.

Glossary: Brief defi nitions of certain terms used under Market Oversight.

Acronyms: Most commonly used acronyms under Market Oversight

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Survey/Feedback link, or by contacting Market Oversight by telephone at 202-502-8278 or by email oversight@ferc.gov.
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In alphabetical order, contributors include: 

Bill Booth, Florence Bresnahan, Allison Browning, 

Lee-Ken Choo, Keith Collins, David Dorleans, Judy Eastwood, 

Sidney Givens, Bob Flanders, Alan Haymes, John Harvey, 

Stephen Harvey, Lance Hinrichs, Matthew Hunter, 

Raymond James, John Jennrich, Ryan Jett, David Kathan, 

Ken Kohut, Gary Mahrenholz, Kamaria Martin, 

Eileen Merrigan, Steven Michals, Ray Palmer, Chris Peterson, 

Tom Rieley, Karen Robinson, Jeff Sanders, Saida Shaalan, 

Dave Sharma, Timothy Shear, Julia Tuzun, Laura Vallance, 

Carol White, Charlie Whitmore, and Dean Wight.

Acknowledgments

Researching, writing and producing the 2006 State of the Markets Report was a 

group effort. With so many long and hard hours put in to complete this project, no 

acknowledgements list can do justice to the impressive efforts of so many people.