Natural Gas Markets: Overview and Policy Issues
Natural Gas Markets:
Overview and Policy Issues
May 23, 2008
William F. Hederman, Jr.
Specialist in Energy Policy
Resources, Science, and Industry Division
Natural Gas Markets: Overview and Policy Issues
The functioning of the natural gas market in 2007 appeared relatively stable and
infrastructure development continued at an appropriate pace. A tighter
demand/supply balance for 2008, however, has generated more upward spot price
movement in this latest period. From the beginning to the end of the 2007-2008
heating season, the average wellhead price rose more than 30%, according to Energy
Information Administration estimates. In the foreseeable future, weather and
economic performance appear most likely to influence prices.
Natural gas provided about 22% of U.S. energy requirements in 2007. It will
continue to be a major element of the overall U.S. energy market for the foreseeable
future. Given its environmental advantages, it will likely maintain an important
market share in the growing electricity generation applications, along with other
clean power sources.
As Congress seeks to address energy security issues, the increasing importation
of liquefied natural gas (LNG) is also a matter deserving careful attention. In 2007,
LNG imports reached a record high and plans are to increase this fuel source.
This report provides an update to Congress on recent natural gas market
developments and trends that have implications for important energy policy
considerations, such as prices, natural gas use for power generation, and liquefied
natural gas imports.
From 2006 to 2007, the average wellhead price reported to the U.S. Energy
Information Administration (EIA) remained essentially unchanged at $6.39 per
thousand cubic feet (mcf), down $0.01. The average citygate price increased about
3% to $6.98 per mcf. Domestic production grew, up about 0.8 trillion cubic feet, and
domestic consumption increased more than 1 trillion cubic feet. This was the first
increase in end-use consumption since 2004, according to EIA.
Natural gas use for electric power generation increased in 2007 by 10.5% and
for the first time became the largest sector for natural gas consumption in the period
covered by EIA records. Residential use increased 8.2%, with weather as a major
factor. Commercial and industrial consumption also increased, by 6% and 2%,
respectively. The industrial growth reversed a decline of 1.5% from 2005 to 2006.
On the supply side, onshore production in areas such as the Rocky Mountains
and the Barnett Shales of Texas grew and liquefied natural gas (LNG) imports
increased. LNG imports reached a record level of 0.8 trillion cubic feet.
EIA’s Short Term Energy Outlook anticipates the Henry Hub spot price
increasing almost 20% in 2008, reflecting strong demand, relatively low working gas
in storage, and domestic production growth of almost 3%. The Henry Hub spot price
did increase about 20% between the first quarter 2007 and first quarter 2008.
This report will be updated. This report supersedes CRS Report RL33714.
In troduction ......................................................1
Increasing Gas-for-Power Use...................................10
Industrial Gas Use Rebound....................................10
Global LNG Trade............................................10
Forecast s .......................................................11
List of Figures
Figure 1. Monthly Natural Gas Consumption: Total and Electric Power Use
Figure 2. Comparison of Natural Gas and Competing Oil Product Prices
List of Tables
Table 1. U.S. Natural Gas Wholesale Price Overview.....................4
Table 2. U.S. Retail Price overview ...................................5
Table 3. U.S. Natural Gas Consumption Overview.......................6
Table 4. U.S. Natural Gas Supply Overview............................7
Table 5. Lower-48 LNG Overview ...................................8
Table 6. Infrastructure Complete in 2007..............................11
Table A1. Selected Natural Gas Market Statistics Prices..................16
Table A3. Supply................................................16
Table A4. Infrastructure Projects into Service in 2007....................17
Natural Gas Markets: Overview and Policy
Natural gas markets in North America remained relatively stable compared to
oil markets in 2007. The situation has tightened and prices have regained some
upward momentum in 2008.
This report examines current conditions and trends in the U.S. natural gas
markets. Key market elements examined include prices, consumption, production,
imports, and infrastructure. Expectations about the future, as reflected in recent
official forecasts, are also incorporated here.
Natural gas remains an important and environmentally attractive energy source
for the United States. Its share of the power generation market has grown. Domestic
supply has remained stable and even increased in recent months. New developments
in Alaska increase the likelihood that a pipeline from the North Slope will proceed.
The natural gas industry continues to attract capital for new pipeline and storage
infrastructure. Liquefied natural gas (LNG) imports hit a record level in 2007, even
as import facilities continue to have low utilization rates. Weather and the economy
remain important factors in natural gas prices, as well.
Given the generally adequate functioning of natural gas markets, congressional
interest in the near term is likely to focus on unexpected price volatility or
importation (or other supply) issues. In the longer term, industry pressure for
increased access to public lands for exploration and production is expected to
continue receiving congressional attention.
This report reviews key factors likely to affect market outcomes. These factors
include weather, the economy, oil prices, and infrastructure development. Tables A1
to A4 (in the Appendix) present selected highlight statistics that illustrate current
Briefly, important developments in natural gas markets include the following:
!The growth in natural gas for power generation has
contributed to increased consumption and reduced seasonal
variation in use because gas-for-power peaks in summer,
versus the total natural gas use winter peak.
!In 2007, for the first time, the power generation sector used
more natural gas than any other sector.
!The first quarter 2008 average spot price at Henry Hub
increased 20% from the first quarter 2007 to $8.92 per
thousand cubic feet (mcf), versus a 6% year-to-year increase
from 2006 to 2007.1 During the 2007-2008 heating season
(October to March), average wellhead prices increased more
than 30%, according to EIA estimates.2
!Storage levels towards the end of the heating season dropped
below five year averages. In the first storage report after the
2007-2008 heating season, working gas storage was at 1,234
billion cubic feet — the lowest level since April 30, 2004.3
This may indicate that slack in the supply side is decreasing.
!The United States had record LNG imports in 2007, and
increased LNG imports appear likely.
!Natural gas infrastructure development continued to advance,
with many pipeline and storage projects successfully
completed in 2007 and more underway in 2008 (including
LNG import facilities).
!Industrial natural gas use had a small rebound in 2007.
Unlike the global oil market, natural gas markets remain generally regional, with
global trade in LNG growing. For the most part, North America has a continent-wide
market that is integrated through a pipeline network that connects the lower-48 states,
the most populous provinces of Canada, and parts of Mexico. Prices throughout this
integrated market are influenced by demand (which may be influenced by weather,
economic conditions, alternative fuel prices, and other factors), supply, and the
capacity available to link supply sources and demand loads (transmission and
The U.S. natural gas market is the major component of the North American
natural gas market. It accounts for about 81% of North American consumption and
about 69% of North American supply.
The key price point in North America is Henry Hub. Henry Hub is a major
pipeline hub in Erath, Louisiana, that is used as the designated pricing and delivery
point for the New York Mercantile Exchange (NYMEX) gas futures contract and
1 Energy Information Administration (EIA), Short-Term Energy and Summer Fuel Outlook,
April 2008, Table 5c.
2 EIA, Natural Gas Weekly Update, April 10, 2008, p. 3.
3 Ibid., p. 3.
other transactions. The price difference between other locations and Henry Hub is
called the “basis differential.” When there is spare capacity available to move natural
gas from Henry Hub, or the Gulf of Mexico region in general, to the relevant price
point area, the basis differential tends to be low, approximating the costs of fuel used
to move the gas to the location. When capacity availability is tight, basis differentials
can grow because the driving force can become the value of the natural gas at the
delivery point, rather than the cost of getting the natural gas to that point.
Natural gas prices also incorporate costs for distributing the gas from the
wholesale marketplace to retail customers. These rates are generally determined by
state regulators and involve both (1) the approval of costs and rates of return and (2)
the allocation of costs among customer classes (e.g., residential, commercial,
Although the North American natural gas market remains a distinct regional
market, it is increasingly connecting to a global gas marketplace through international
LNG trade. Oil prices still affect U.S. natural gas prices and this relationship is
The key elements of the market are prices, consumption, and supply. This
section provides highlights from recent market developments relating to these factors.
Prices remained fairly stable between 2006 and 2007. Early 2008 prices have
increased at a faster pace than in 2007. According to EIA figures, average spot prices
at Henry Hub increased about 6% between 2006 and 2007. (See Table 1 for price
The U.S. Energy Information Administration (EIA) reports producer price data
for its wellhead price series. This price remained stable from 2006 to 2007,
decreasing by $0.01 to $6.39 per mcf in 2007 (average). During the 2007-2008
heating season (October to March), EIA estimates the average wellhead price4
increased more than 30%, to $8.29 per mcf.
The EIA citygate price series reflects the unit prices delivered to consuming
areas.5 The U.S. average citygate price decreased $0.49 to $8.11 per mcf from 2006
Complete import price data for 2007 are not yet available from EIA. From 2005
to 2006, LNG import prices decreased 11.6% to $7.14 per mcf.
4 Ibid., p.3.
5 The “citygate” is the transfer point from a high pressure natural gas pipeline to a local
Table 1. U.S. Natural Gas Wholesale Price Overview
($ per thousand cubic feet)
Month Henry Wellhead Citygate Henry Wellhead Citygate
J a nuary 6.75 5.92 7.89 8.92 8.02 10.80
February 8.24 6.66 8.59 7.76 6.86 9.34
March 7.32 6.56 8.81 7.10 6.44 8.81
April 7.83 6.84 8.19 7.38 6.38 8.29
May 7.87 6.98 8.39 6.45 6.24 7.99
J une 7.57 6.86 8.38 6.39 5.78 7.39
J uly 6.40 6.19 7.94 6.35 5.92 7.40
August 6.37 5.90 7.46 7.35 6.56 8.10
September 6.26 5.61 6.89 5.04 6.06 7.68
October 6.94 6.25 7.36 6.02 5.09 6.42
Nove mber 7.31 6.37 8.05 7.61 6.72 8.47
December 7.32 6.53 8.13 6.90 6.76 8.66
Average 7.17 6.39 8.11 6.74 6.37 8.60
Source: EIA, Natural Gas Monthly (NGM), April 2008, Table 3, for citygate and wellhead; EIA,
Short-Term Energy Outlook, May 2008, Table 2 and backup data, for Henry Hub 2007 and May 2007,
Table 4 for Henry Hub 2006.
At the retail level, average U.S. residential natural gas prices were $13.01 per
mcf in 2007, with a high of $16.65 in July. This average was a 5.4% decrease from
2006. The average commercial price was $11.31 per mcf, a decrease of 5.7% from
2006. Industrial prices decreased 4.6% on average to $7.58 per mcf. Natural gas
sold for electric power use increased prices 2.8% to average $7.30 per mcf. See
Table 2 for these data.
Table 2. U.S. Retail Price overview
($ per thousand cubic feet)
Month El e c t r i c El ectric
Re sidential Commercial Industrial pow e r Resi dent i a l Com m e rci a l I ndust r i a l pow e r
nuary 12.09 11.14 7.33 7.05 14.94 14.15 10.84 9.15
12.12 11.21 8.23 8.16 14.00 12.95 9.35 8.00
12.86 11.81 8.40 7.64 13.29 12.07 8.23 7.36
13.27 11.51 8.13 7.76 13.29 11.57 7.91 7.32
g/w14.61 11.50 8.10 7.96 14.43 11.60 7.62 6.89
leak16.20 11.87 7.98 7.80 15.09 11.09 6.90 6.69
://wikily 16.65 11.63 7.54 7.01 15.73 10.98 6.77 6.69
ust 16.64 11.18 6.57 6.80 16.19 11.20 7.35 7.56
ber 15.94 10.90 6.11 6.35 15.73 11.16 7.20 6.27
14.25 10.80 6.85 7.04 12.52 10.04 5.62 5.76
e mber 12.82 11.04 7.63 7.27 12.47 11.05 7.74 7.48
ber 12.17 11.02 7.97 7.93 12.54 11.61 8.23 7.57
er 13.01 11.31 7.58 7.30 13.75 11.99 7.86 7.11
EIA, NGM, April 2008, Table 3.
Power sector use of natural gas increased most rapidly in 2007, followed by the
weather-sensitive residential and commercial sectors. Total U.S. consumption of
natural gas grew 6.5% from 2006 to 2007, according to EIA. Gas-for-power led the
sectoral growth, increasing 10.5%. Residential consumption increased about 8.2%,
primarily due to colder weather than 2006. The commercial and industrial (without
lease and plant use) sectors also had modest increases in consumption, reversing
drops in use in these sectors for 2005 to 2006. The power sector led end-use
consumption for the first time in 2007.
Table 3 shows these consumption data.
Table 3. U.S. Natural Gas Consumption Overview
Billion cubic feet (Bcf)
YearResidentialElectric powerCommercialIndustrialOther Total
2005 4,827 5,869 2,999 6,597 1,719 22,011
2006 4,368 6,222 2,835 6,495 1,733 21,653
2007 4,724 6,874 3,008 6,635 1,817 23,058
Source: EIA, NGM, April 2008, Table 2.
U.S. natural gas supply comes from domestic production, pipeline imports,
imported LNG, and net withdrawals from storage. Both domestic and imported
supplies increased between 2006 and 2007.
Dry gas production increased by 4.3% from 2006 to 2007, to 19,278 billion
cubic feet (Bcf). This reflects the increase in drilling activity in response to price
increases, as indicated in the natural gas rig count. The U.S. natural gas rig count has
trended upward since 2002. In 2002, the average monthly rig count was about 600.
Recent data show the count at approximately 1,500.6
6 FERC, Division of Market Oversight, OE, Winter 2007/2008 Energy Market Assessment,
Item No. A-3, October 18, 2007, “Gas Drilling Continues to Rise,” no page, citing Baker
Hughes and EIA.
The U.S. natural gas reserve base increased recently. EIA reserves and
production data indicate the latest reserves-to-production ratio7 (2006) is 11.4, an
increase from the prior year’s ratio of 11.1 and 2000’s ratio of 9.2.8
In 2007, U.S. consumers received most of their supply, 84%, from domestic
production. The domestic supply has shifted from shallow Gulf of Mexico to deep
Gulf of Mexico and unconventional sources, in the Rocky Mountains and elsewhere.9
As these new resources grow in importance, industry pressure for increased gas
leasing of on- and offshore federal lands is likely to be a continuing issue.10
Net imports (pipeline and LNG) increased almost 10%, to 3,793 Bcf. Imports
via pipeline from Canada increased 5%. LNG imports increased more than 32%,
growing from 584 Bcf in 2006 to 771 Bcf in 2007.11
Table 4 show these data.
Table 4. U.S. Natural Gas Supply Overview
YearDry GasproductionNetimportsNet storagewithdrawalsOther/balancingTotal
2006 18,476 3,462 -436 151 21,653
2007 19,278 3,793 177 -193 23,055
Source: EIA, NGM, April 2008, Table 1 and CRS calculations.
In 2007, the available spot LNG supplies were sometimes bid away to European
terminals for higher prices. Nevertheless, new U.S. LNG infrastructure went into
service in early 2008 and still more received approvals from the Federal Energy
Regulatory Commission (FERC). To compete effectively for supply in the global
LNG market, natural gas prices at the delivery points may have to increase further to
7 The reserves-to-production ratio divides the nation’s proven reserve figure by the annual
production to get this metric of supply inventory.
8 EIA, available at [http://tonto.eia.doe.gov/dnav/ng/ng_enr_dry_dcu_NUS_a.htm].
9 Conventional natural gas supplies are produced by conventional drilling and extraction.
Unconventional gas involves more advanced technology, such as extraction of methane from
coal beds or from tight formations requiring fracturing and other techniques.
10 For more discussion, see CRS Report RL33493, Outer Continental Shelf: Debate over Oil
and Gas Leasing and Revenue Sharing, by Marc Humphries.
11 EIA, NGM, April 2008, Table 4.
attract LNG deliveries. Location of import facilities is an important factor in the
value of landed LNG.12
Table 5. Lower-48 LNG Overview
Deliver- Average Deliver- Average Estimateddeliver-
Terminal ability delivery ability delivery ability
EOY 20062006EOY 200720072008
Northeast - - 0.8 N.A. 0.8
Gul f 0.5 N.A. 0.5 N.A. 0.5
Hackberry -- --1.8
Source: EIA, US Natural Gas Imports and Exports:2006, March 2008, figure 1 and EIA, Short-Term
Energy Outlook Supplement: U.S. LNG Imports - The Next Wave, January 2007, pp. 9-10.
EIA forecasts U.S. imports of 1,080 Bcf LNG for 2008, including regasified
LNG from Mexico’s Costa Azul terminal in Baja California.13 In addition, an LNG
import facility in eastern Canada largely focused on exporting to the United States
is expected to enter service in 2008.
12 This siting issue is discussed in greater detail in CRS Report RL32386, Liquefied Natural
Gas (LNG) in U.S. Energy Policy: Infrastructure and Market Issues, by Paul Parfomak,
updated January 31, 2006.
13 EIA, Short-Term Energy Outlook, January 2007, p. 8.
There are several trends under way in natural gas markets of interest to policy
makers. They include:
!a decrease in seasonal demand swings
!a growth in gas-for-power use
!a small rebound in industrial use of natural gas
!a growing international trade in LNG
!continuing progress in natural gas infrastructure development.
Consumption of natural gas in the United States remains highly seasonal for
three important sectors. Reflecting the importance of space heating, residential and
commercial use of natural gas peaks in winter. Reflecting the importance of air
conditioning load and the role of natural gas as the marginal fuel source for power
generation, electric power use of natural gas peaks in summer.
Figure 1. Monthly Natural Gas Consumption: Total and Electric
-0 0 n- 0 1 c-01 n- 02 ec -0 2 n- 0 3 c-03 n- 04 c- 04 n- 0 5 ec -0 5 n- 06 c-06 n- 0 7 ec -0 7
D ec Ju De Ju D Ju De Ju De Ju D Ju De Ju D
Total consumptionGas for power
Source: CRS graphic, data from U.S. Energy Information Administration, Natural Gas Navigator,
available at [http://tonto.eia.doe.gov/dnav/ng/ng_cons_sumc_duc_nus_m.htm]
Figure 1 illustrates that the combination of these seasonal patterns has led to
a decrease in the overall seasonal swing and the development of a secondary peak in
the summer due to gas-for-power use. Interestingly, while some continue to call for
more storage because of the growing consumption of natural gas, the decrease in the
seasonal swing (through a decrease in the high month volume and an increase in the
low month volume) means that less storage may be able to serve the annual cycling
needs of the U.S. markets. Those trading natural gas may want additional storage for
arbitrage uses, but the fundamental needs related to system reliability may decrease
somewhat with a decrease in the difference between the minimum and maximum
Another noteworthy seasonal feature observed in 2007 by EIA found that natural
gas price volatility is “considerably higher” in colder months than in other times.14
Increasing Gas-for-Power Use
The natural gas consumption sector with the greatest increase from 2006 to 2007
was electric power. Deliveries to electric power customers increased by 615 Bcf,
more than 45% of the consumption growth for the year. For the first time, electric
power use of natural gas became the largest end-use sector for natural gas.15
Perhaps even more striking is the relative increase in electric generator use of
natural gas during winter. In 2007, FERC’s Division of Energy Market Oversight
noted that November-March volumes increased 14% between winter 2005/06 and
Industrial Gas Use Rebound
Industrial natural gas use in 2006 was approximately 13% lower than the 7,507
Bcf consumed in 2002. In 2007, industrial use increased by 2% over the 2006 level.
The decrease in price to industrial users may have played a role in this effect.
Global LNG Trade
In 2007, LNG monthly imports varied from a high of 98.7 Bcf in April to a low
of 20.8 Bcf in December. Because little of the LNG is imported under long term
contracts, U.S. importers compete on the global LNG spot market for deliveries.
In December 2007, European natural gas prices were in the $10.20-$10.66 per
million Btu range. U.S. prices varied above and below this. New England citygates
were at $12.16 per million Btu and Henry Hub was at $7.15 (the Algonquin citygate
figure represents several citygates in New England). Thus, some import points could
compete successfully in the global spot market for LNG and others could not.17
There is excess physical capacity at existing LNG import facilities to handle more
than three times the record imports of 2007.
14 EIA, An Analysis of Price Volatility in Natural Gas Markets, August 2007, p.2.
15 This excludes lease and plant gas use from the industrial sector, where it sometimes is
16 FERC, Division of Market Oversight, Winter 2007/2008 Energy Market Assessment, Item
No.: A-3, October 18, 2007, “Electric Generators Using More Winter Gas,” no page.
17 FERC, Division of Market Oversight, Office of Enforcement, OE Energy Market
Snapshot, February 2008, National Version, p. 28.
During 2007, the North American natural gas industry continued its progress in
adding new infrastructure to the system. According to EIA and the FERC, the
following facilities went into service in the United States in 2007. These facilities
appear responsive to serving fundamental market needs, such as new capacity from
the growing Rocky Mountains production area. Although no new LNG facilities
became operational in 2007, facilities are expected to achieve commercial operation
Table 6. Infrastructure Complete in 2007
Type of projectNumber of projectsCapacity
Pipelinesmore than 5014.9 Bcf/d
LNG import terminals0-
Storage facilities91.8 Bcf/d
Sources: EIA, Office of Oil and Gas, Natural Gas Year-In-Review, March 2008, p.5 and FERC,
Winter 2007/2008 Energy Market Assessment, Item No.: A-3, October 18, 2007, “What has been
placed into service,” no page.
There are a few noteworthy elements of recent EIA forecasts for the natural gas
In its Short Term Energy Outlook, EIA forecasts a 1% increase in natural gas
use for 2008, relative to 2007. Weather changes and economic conditions are the
reasons EIA mentioned for the slowed growth. Prices are also likely to reinforce a
short term slowdown in use. EIA forecasts record U.S. consumption of 23.4 trillion
cf in 2009. EIA forecasts increased U.S. production in 2008 of almost 3%, primarily
from growth in deepwater Gulf of Mexico and unconventional gas production. LNG
imports are expected to decline about 14% from 2007. EIA forecasts supply area
natural gas prices (Henry Hub) to increase almost 20% in 2008 to $8.34 per million
In EIA’s long term forecast (through 2030), the reference case forecasts natural
gas prices at the wellhead gradually decreasing to $5.27 per mcf during the 2015 to
EIA forecasts natural gas consumption growth to 24.4 trillion cubic feet (tcf) in 2015,
declining to 23.4 tcf by 2030. Most of this increased use and the drop come from
growth, then decline, in natural gas for power generation. EIA forecasts the arrival
of Alaska Natural Gas to the lower-48 via pipeline in 2020, with deliveries reaching
EIA’s forecast of gradual reductions in natural gas prices depends on certain
assumptions embedded in the forecast. These factors have uncertainty associated
with them, as discussed next.
Weather affects natural gas consumption through both the significant space
heating loads in the residential and commercial sectors and the cooling load served
by gas-fired power generation. EIA incorporates National Oceanic Atmospheric
Administration (NOAA) weather forecasts in its short and long term forecasts. To
the extent that actual heating degree days exceed the temperature scenario from
NOAA, that will tend to increase demand for natural gas in the relevant heating
seasons and increase prices for natural gas during those periods. Similarly, if the
actual cooling degree day requirements exceed those incorporated in the EIA
scenario, then this will increase natural gas use in the cooling season via increased
gas-fired power for air conditioning and increase the price for natural gas in the
relevant cooling season.
Natural gas prices and oil prices have long had a correlation. As the extent of
oil/gas fuel switching has declined, this linkage has changed. During 2007, as crude
oil and petroleum product prices increased, relative prices for natural gas became
lower than the historical pattern. In the recent past, natural gas and oil product price
competition tended to exhibit itself most clearly around the New York metropolitan
area, where there remained a fair amount of fuel switching capability. This fuel
switching capability tended to keep natural gas prices at the New York citygate in a
range bounded on the high side by distillate fuel oil prices and on the low side by low
sulfur residual fuel oil prices. In 2007, the relevant natural gas prices tended to be
below this range (see Figure 2).
18 EIA, Annual Energy Outlook 2008, p.10.
Figure 2. Comparison of Natural Gas and Competing Oil Product
Source: FERC, Division of Market Oversight, Office of Enforcement, OE Energy Market
Snapshot, National Version - December 2007 data, January 2008, p. 23.
The shift to outside this fuel price range suggests that the consumers had done
all the fuel switching to natural gas that remained feasible. Then, as oil prices moved
above the relevant range, gas-on-gas competition could have become the market
force determining the natural gas prices.
Economic growth affects consumers’ demand for natural gas and their ability
to purchase it. EIA appears to have incorporated an economic outlook for 2008 that
expects less growth than in its recent forecasts. Given the relative stability in the
residential and commercial sector demand, any change in economic outlook would
most likely affect industrial natural gas use most directly, but it could also affect
commodity prices and world oil prices.
Since the end of 2007, several noteworthy developments have occurred in the
natural gas markets:
!EIA reports natural gas price increases in 2008. For the 2007-2008
heating season (November-March), the average spot price at the
wellhead increased more than 30% from the beginning to the end of
heating season, to $8.06 per million Btu.19
!Storage levels towards the end of the heating season dropped below
five year averages. In the first storage report after the 2007-2008
heating season, working gas storage was at 1,234 billion cubic feet,
19 EIA, Natural Gas Weekly, April 10, 2008, p. 3.
the lowest level since April 30, 2004.20 This may indicate that slack
in the supply side is decreasing.
!The opening of the Rockies Express natural gas pipeline out of the
Rocky Mountain production region appears to have relieved
transmission congestion there. This improved the net back price
within the production area.21 The wellhead price in the Rockies area
increased from $4.82 per million Btu in November 2007 to $8.41 in
March 2008.22 This improves the incentives for producers to find
and develop new supplies in this area.
!The natural gas pipeline from the North Slope of Alaska has made
progress. In January 2008, the Governor of Alaska announced that
one of the pipeline project applications under the state Alaska
Gasline Inducement Act (AGIA) was judged complete. In April
announced that they had joined together to start a potentially
competing effort, the Denali Alaska Gas Pipeline, which has an open
season target date (date when capacity will be offered to potential
shippers) of 2010 and an in-service target of 2018 (stated by the
producers as a 10-year target).23
!In early April, the Independence Trail pipeline that serves the
Independence Hub platform in the Gulf of Mexico was taken out of
service for pipeline repairs that could take until mid-year to
complete. Independence Hub produces almost 1 billion cubic feet
per day, roughly 10% of U.S. Gulf of Mexico production.
!In May, the North American Electric Reliability Corporation
concluded the natural gas supply outlook for the summer of 2008 is
“heal t h y. ”24
Generally, these developments indicate that the nation’s natural gas market is
functioning in tune with fundamental supply and demand conditions.
20 Ibid., p.3.
21 The “net back price” is the price a producer receives based on the price at the end-use
market minus the cost of transmission to that market.
22 Ibid., p.4.
23 Denali, presentation, April 8, 2008.
24 North American Electric Reliability Corporation, 2008 Summer Reliability Assessment,
May 2008, p. 12.
Despite the problems arising in some parts of the energy system, natural gas fuel
markets in North America have operated relatively well. The smooth natural gas
market situation of 2007 appears to have evolved into different, tighter circumstances
for 2008. If gas-on-gas competition declines and natural gas prices shift back into
a competitive range with petroleum products, this will intensify the adverse effects
of high oil prices.
The decline in seasonal consumption swings, primarily due to the increased use
of gas-for-power, can improve the efficiency with which the nation’s natural gas
pipeline and storage infrastructure is used. Construction of new pipeline and storage
infrastructure has continued to progress in a way apparently consistent with supply
and demand fundamentals.
Finally, LNG infrastructure development also continues. The low current
capacity factors at the capital-intensive existing LNG import facilities may indicate
that the U.S. LNG purchasing power is not proving as competitive in the
international LNG market as project developers or those reviewing the projects had
anticipated. The location of LNG facilities has an important effect on this potential
competitiveness, and this factor may require greater consideration for future projects.
How weather and the economy perform will play an important role in whether
prices continue to increase or downward pressure develops for natural gas as a
Table A1. Selected Natural Gas Market Statistics Prices
(2003-2007)Annual De c e m b e r Annual De cember
Wellhead 6.39 6.53 6.40 6.76 4.88-7.33
Residential 13.01 12.17 13.75 12.54 9.63-13.75
Table A2. Consumption
(trillion cubic feet)
T otal 23.0 21.7 21.7-23.0
Residential 4.7 4.4 4.4-5.1
Comme rcial 3.0 2.8 2.8-3.2
Industrial 6.6 6.5 6.5-7.2
Table A3. Supply
(trillion cubic feet)
U.S. dry gas production19.318.5 18.1-19.3
Table A4. Infrastructure Projects into Service in 2007
Sources: Energy Information Administration (EIA) and Federal Energy
Regulatory Commission (FERC), various documents, detailed in body of