Natural Gas Markets in 2006
Congressional research reportDec 12, 2006
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Natural Gas Markets in 2006
-name redactedSpecialist in Energy Economics
December 12, 2006
Congressional Research Service
7-....
www.crs.gov
RL33714
CRS Report for Congress
Prepared for Members and Committees of Congress
Natural Gas Markets in 2006
Summary
The Energy Information Administration (EIA) in its Short Term Energy and Winter Fuels Outlook
(STEWFO) provided good news for residential natural gas consumers. EIA projected that natural
gas winter home heating costs might decline by as much as 13% from last year’s record-setting
levels, even though consumption is expected to increase this winter. The STEWFO sees prices for
natural gas lower than last year as a result of weak market fundamentals.
Analyses of natural gas market demand and supply conditions seem to be consistent with the EIA
STEWFO. Aggregate consumption of natural gas over the first seven months of 2006 has
declined compared to 2005. U.S. production, as well as imports, have also declined over the same
time period, likely in response to the decrease in consumption. On a sectoral level, the decline in
consumption has included all consumer groups except electric power generators, whose
consumption rose. Storage of natural gas, the factor that balances yearly demand and supply, is at
an all time record high level, and is approaching the maximum physical capacity of the system.
There does not appear to be any fundamental imbalance between demand and supply in the 2006
natural gas market, making a stable, or even declining, price level likely.
The price of natural gas is actually many prices. Small, residential, consumers typically pay the
highest prices per unit of natural gas, and large industrial and electric power consumers pay the
lowest prices per unit. Taken in this context, the 2006 price outlook may be less favorable than
the EIA suggests, across different sectors. Residential prices had not responded to falling
wellhead prices as of July 2006. The past several years of high gas prices have yielded a 14%
decline in industrial consumption, and that demand may not return to the market.
Risk factors, including weather conditions, movements in the price of crude oil, and
developments in the futures markets all could affect the market balance in the natural gas market.
Because these factors have caused price volatility in the past, the EIA outlook may best be
considered as conditional on outcomes in these areas.
This report will be updated.
Congressional Research Service
Natural Gas Markets in 2006
Contents
Background ................................................................................................................................1
Market Conditions 2006..............................................................................................................2
Consumption.........................................................................................................................2
Production and Imports .........................................................................................................4
Storage..................................................................................................................................4
Prices....................................................................................................................................5
Short-Term Forecast..............................................................................................................8
Risk Factors................................................................................................................................9
Weather ................................................................................................................................9
Oil Prices ..............................................................................................................................9
Futures Markets .................................................................................................................. 10
Conclusion................................................................................................................................ 10
Tables
Table 1. U.S. Natural Gas Consumption ......................................................................................3
Table 2. U.S. Wellhead Natural Gas Price....................................................................................5
Table 3. U.S. Residential Natural Gas Price.................................................................................6
Table 4. U.S. Commercial Natural Gas Price ...............................................................................6
Table 5. U.S. Industrial Natural Gas Price ...................................................................................6
Table 6. U.S. Industrial Consumption of Natural Gas...................................................................7
Table 7. U.S. Electric Power Generator Natural Gas Price ...........................................................8
Contacts
Author Contact Information ...................................................................................................... 10
Congressional Research Service
Natural Gas Markets in 2006
T
he Energy Information Administration (EIA), in its October 2006 Short-Term Energy and
Winter Fuels Outlook (STEWFO), provided encouraging news for residential natural gas
consumers.1 Their 2006-2007 winter heating bills were projected to decline by an average
of about $119 per household, or 13%, from 2005-2006 levels.2 This anticipated decline in
consumer costs is related to market conditions in 2006 that have been quite different from those
observed a year ago.
This report analyzes the key factors affecting prices in the U.S. natural gas market, including
consumption, production, reserves, and storage levels. The current environment of declining
prices is compared to last year, as well as near-term future projections that continue to show a
tight market and high prices.
Background
The U.S. natural gas market is a regional market, drawing supplies from domestic sources as well
as imports, via pipeline, from Canada. In addition, a small part of domestic supply is imported in
the form of liquefied natural gas (LNG) which is part of a small, but growing, world market. As a
result of the regional nature of natural gas markets around the world, prices may differ across the
various regions. 3
Within the U.S. market, different groups of consumers pay different prices for natural gas.
Residential, commercial, industrial, and electric power consumers are the largest groupings, with
transportation uses the newest category. Cost of distribution, as well as scale of quantity
purchased, determine price paid, although in some cases state regulatory commissions can
determine some prices. In general, residential consumers constitute the largest customer base
(over 62 million in 2004), purchase the smallest quantities per customer, and pay the highest
prices. Electric power generators consume large quantities, and pay the lowest per unit price.
Historically, industrial consumers were the largest consumers of natural gas, although their
aggregate consumption has declined in recent years.
On the supply side, in 2005, domestic production provided about 83% of consumption, imports
via pipeline from Canada accounted for approximately 16%, and LNG, mostly from Trinidad,
accounted for about 2%.4 Production represents a draw from the reserve base. In the U.S., the
reserve base, measured by the reserve to production ratio, has been growing, increasing from 8.8
years in 1997 to 10.4 years in 2004.5
1
Energy Information Administration, Short-Term Energy and Winter Fuels Outlook, October 2006.
The winter heating season runs from November to March.
3
A large, worldwide, LNG spot market could reduce these price differentials. At present, most LNG is traded through
long-term contracts that have the effect of perpetuating the regional character of the markets.
4
Total does not add up to 100% because of rounding.
2
5
The reserve to production ratio measures the number of years then current production can be sustained. If this ratio is
increasing, more natural gas is being added to the reserve base through discovery than is being drawn down due to
production and consumption. However, the new gas added to the reserve base may be more expensive to produce.
Congressional Research Service
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Natural Gas Markets in 2006
Storage is an important component of natural gas supply because while production tends to be
relatively constant throughout the year, consumption tends to peak during the winter heating
season (November through March) as home heating use rises and tends to moderate in the other
seasons.6 For this reason, the industry injects gas into storage facilities to prepare for winter
heating season demand peaks. In recent years, the industry has established a target of over 3
trillion cubic feet (tcf) of gas in storage for this purpose.
While price is an important determinant of consumption and production in the market at the
aggregate level, the weather is perhaps even more important in consumption decisions by
residential consumers. The primary use of natural gas by residential consumers, home heating,
tends to be quite price inelastic; consequently, the onset of cold temperatures causes demand
peaks largely independent of the level of prices.
Market Conditions 2006
Consumption
Aggregate consumption of natural gas in the United States for the first seven months of 2006 was
4.1%, or 551 billion cubic feet (bcf), lower than the comparable period in 2005.
Table 1 shows how this decrease in consumption, for comparable time periods, was divided
between the consuming market segments. Residential consumption declined by the largest
amount in both percentage and volume terms. Commercial demand also decreased by more than
the average for the market. Industrial demand decreased by more than the average for the market,
but this decline may be part of a long term fall in industrial demand of approximately 19% over
the period 2000 to 2005. Consumption by electric power generators is a derived demand in the
sense that their demand for natural gas is dependent on, and derived from, consumers’ demand for
electric power, which has been growing. The use of natural gas in transportation vehicles is a very
small, but growing portion of the total market.
The key factors in explaining the observed reductions in natural gas consumption over the past
year are price and the weather. Although these two factors affect all market segments, their
relative effects vary across the market segments.
6
Recently, however, because of the increasing use of natural gas in electric power generation, summer use rates have
increased as air conditioning demand increases.
Congressional Research Service
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Natural Gas Markets in 2006
Table 1. U.S. Natural Gas Consumption
(in billion cubic feet)
Sector
2005
2006
% change
Residential
3,225
2,863
-11.2
Commercial
1,968
1,827
-7.1
Industrial
3,996
3,788
-5.1
Electric Power
3,254
3,433
5.5
12
13
8.8
12,457
11,926
-4.2
Vehicles
Total
Source: Energy Information Administration, available at http://www.eia.doe.gov.
Note: Data for each year is for the period January to July in each year.
Average U.S. residential natural gas prices were $14.64 per thousand cubic feet, (mcf) in the
winter of 2005-2006, a peak price for the decade, 57% above the average residential price for the
period 2000-2005, and an increase of 32% over the previous winter heating season. Probably
more important, the winter heating season in 2005-2006 was also warmer than normal for the
United States as a whole, as measured by population weighted heating degree days. These two
factors, warm weather, coupled with high prices, likely accounted for a large portion of the
reduced demand observed in the residential sector.
Commercial demand is, like residential demand, largely used for space heating. As a result, this
sector’s consumption is also likely to be relatively insensitive to changes in price, and quite
sensitive to weather variations.
Industrial consumption of natural gas is likely to be more sensitive to price variations, and less
sensitive to weather variations than residential or commercial consumption. Natural gas is used in
production processes both as a raw material, for example, in the nitrogenous fertilizer industry,
and as a source of process heat, as in the steel industry. Many of the domestic industries that use
large quantities of natural gas cannot easily pass cost increases on to final consumers because
they face competition from overseas producers who have access to cheaper sources of natural gas.
As a result of this inability to remain competitive in the face of increased natural gas prices in the
United States, some firms have either ceased domestic production, or moved their facilities
overseas, accounting for the decrease in U.S. industrial natural gas consumption.
The electric power sector’s consumption of natural gas depends on the demand for electricity,
which itself is dependent on the price of electricity and the weather in the short term.
Consumption is also affected by the primary fuel choice for the mix of power generators in the
supply base, fuel switching capability, and how production is divided between baseload and peak
power generation.
The use of natural gas in transportation vehicles is largely for commercial purposes, for example,
city bus fleets. As such, this sector’s consumption might be expected to be relatively insensitive
to the price of natural gas as well as weather conditions.
Congressional Research Service
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Natural Gas Markets in 2006
Production and Imports
Aggregate dry natural gas production in the United States for the first seven months of 2006 was
2.8%, or 307 bcf, lower than in the comparable period in 2005. Production data for the first seven
months does not, however, provide a complete picture of the 2005-2006 winter fuels market from
the producer’s side, because the effects of hurricanes Katrina and Rita were felt largely in the
fourth quarter of 2005, and into 2006. The hurricanes disrupted natural gas production and
deliveries from the Gulf Coast region by about 6.7 bcf per day, or about 11% of average daily
U.S. consumption. The effect of the hurricanes on natural gas production continued to be
important during the first quarter of 2006 and persisted through the summer of 2006.
Imports of natural gas come mainly from Canada through pipelines. Comparing the period
January to July 2006 and 2005, imports from Canada declined by about 3.5%, a smaller decline
than that of U.S. consumption of natural gas. LNG imports into the United States come mainly
from Trinidad, which supplied almost 70% of U.S. consumption, as well as Nigeria, Algeria, and
other nations. However, the quantities are small in the aggregate. LNG supplied only 2.8% of
total U.S. natural gas consumption in 2005. Over the first seven months of 2006, imports of LNG
have declined by 2.7%.
Storage
Consumption of natural gas is governed by two weather related cycles; one somewhat
predictable, the other less so. The first cycle is yearly; average consumption rises during the
winter heating season (November to March), and is lower in the spring and fall seasons. The
second pattern, less predictable as to timing, is that extremely cold weather conditions yield sharp
increases in consumption. Taken together with a relatively constant rate of production, these
patterns create the need for natural gas storage capacity.
The typical yearly pattern is that stored gas is withdrawn during the winter heating season, and
replenished with storage injections during the following spring, summer, and fall seasons. A
relatively new development in this process is that summer storage injections can be interrupted by
periods of extremely hot weather. As peak electric power generating capacity has become fired by
natural gas to a greater extent, the summer gas injection season can become disrupted by peak
electricity demand conditions.
The industry ideally plans to carry an average natural gas storage inventory of approximately 3.3
to 3.5 tcf at the start of the winter heating season. The estimated maximum storage capacity in the
United States is 3.6 tcf. On December 1, 2006 the amount of natural gas in storage was 3.406 tcf,
which was 232 bcf more than at the comparable time in 2005, and 282 bcf above the five year
average quantity in storage at the end of November 2006. The EIA estimates that stored natural
gas will amount to 1.69 tcf by the end of the 2006-2007 winter heating season. This level of
stored gas is above the five year average.7
The high levels of stored gas attained as the winter 2006-2007 heating season begins suggests that
the market is well supplied, unlikely to experience physical shortages, and is likely to experience
moderate price levels.
7
Energy Information Administration, Short-Term Energy Outlook, December 12, 2006.
Congressional Research Service
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Natural Gas Markets in 2006
Prices
A number of prices are monitored by analysts of the natural gas industry. There is a spot market
price set at the Henry Hub in Louisiana, and a futures market price set at the New York
Mercantile Exchange (NYMEX) in New York City. The wellhead price is paid to producers of
natural gas, while various classes of consumers, residential, commercial, industrial, and electric
power generators each have their own pricing structure. The city gate price reflects the delivered
price of natural gas to various major consuming markets as it is delivered to large distributors.
The import price of natural gas is paid to those suppliers who deliver natural gas to the United
States either by pipeline, or in the form of LNG.
Historically, the ratio of the price of a barrel of crude oil to the price of one thousand cubic feet
(mcf) of natural gas has been 6:1, based on equivalent heat content. During the last three years of
elevated crude oil prices, the ratio has risen as high as 13:1, suggesting that customary linkages
between the two markets may have weakened as factors such as political risk affected the world
oil market.
Table 2 shows the comparative wellhead price of natural gas from January to July, for 2006
and 2005.
Table 2. U.S. Wellhead Natural Gas Price
(in dollars per mcf)
January
February
March
April
May
June
July
2005
5.52
5.59
5.98
6.44
6.02
6.15
6.69
2006
8.66
7.28
6.52
6.59
6.19
5.80
5.82
Source: Energy Information Administration, available at http://www.eia.doe.gov.
The average U.S. wellhead price for the first seven months of 2006 was $6.69 per mcf, compared
to $6.05 per mcf for the comparable period in 2005, a 10.5% increase. However, the average
prices in June and July 2006 were lower than the corresponding prices in 2005, suggesting that
while prices were heading upward in the last five months of 2005, they may be turning downward
as we approach the last five months of 2006.8 The wellhead price for January to March 2006 is
the second half of the winter 2005-2005 heating season, and reflects record setting price levels
due to supply disruptions associated with hurricanes Katrina and Rita.
In general, 2006 has seen declining wellhead prices for natural gas, compared to 2005, and a
relatively weakening market, as shown by the generally declining differences between the
monthly prices, a difference which became negative in June and July of 2006.
While wellhead prices began to moderate in 2006, Table 3 shows that residential prices did not
follow the pattern set by wellhead prices.
8
The average wellhead price of natural gas over the period August to December 2005 was $9.54 per mcf, the highest
average price in the EIA data set going back to 1976.
Congressional Research Service
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Natural Gas Markets in 2006
Table 3. U.S. Residential Natural Gas Price
(dollars per mcf)
January
February
March
April
May
June
July
2005
11.00
10.98
10.95
11.98
12.83
13.88
14.96
2006
14.92
13.99
13.10
13.26
14.37
14.96
15.63
Source: Energy Information Administration, available at http://www.eia.doe.gov.
Residential prices for the last five months of 2005 averaged $15.86 per mcf and consumers paid
record costs for natural gas during the 2005-2006 winter heating season. The estimated decline of
13% in natural gas heating costs projected by the EIA for the winter 2006-2007 heating season,
are from record high prices the previous year. Residential prices continued to increase in June and
July 2006, even as wellhead prices were beginning to moderate. If the margin between wellhead
and residential natural gas prices widens, it is possible that consumers will not benefit fully from
the weakening of market fundamentals.
As shown in Table 4, commercial prices for natural gas were lower than residential prices, and
were slowly moderating from the peak levels attained earlier in the year.
Table 4. U.S. Commercial Natural Gas Price
(dollars per mcf)
January
February
March
April
May
June
July
2005
10.17
9.96
10.07
10.41
10.55
10.48
10.83
2006
14.26
13.11
12.11
11.63
11.76
11.30
11.28
Source: Energy Information Administration, available at http://www.eia.doe.gov.
Table 5 shows the comparative movement of natural gas prices for industrial consumers for the
period January to July, 2005 and 2006.
Table 5. U.S. Industrial Natural Gas Price
(dollars per mcf)
January
February
March
April
May
June
July
2005
6.96
7.06
7.03
7.65
7.11
6.84
7.35
2006
10.84
9.30
8.24
7.92
7.66
6.85
6.69
Source: Energy Information Administration, available at http://www.eia.doe.gov.
Congressional Research Service
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Natural Gas Markets in 2006
Industrial consumers use natural gas both as a raw material in production processes (nitrogenous
fertilizer industry) and as a process heating fuel (some primary metals industries). Many
industrial consumers face an internationally competitive market for their products and find it
difficult to pass cost increases along to consumers. Because the natural gas market is not
worldwide, but regional in scope, different prices for natural gas can coexist in different parts of
the world, without market forces that might tend to equalize them. As a result, an industry that
faces high natural gas prices, and for whom natural gas is a large element in the cost structure of
their products could ultimately face the choice of keeping prices at competitive levels and
suffering reduced profits, or even losses, or closing domestic plants, and moving production
capacity overseas.
Once an industrial consumer of natural gas makes a decision to either go out of business because
of low profits resulting from high costs, or decides to move production capacity overseas to take
advantage of lower costs, it is not likely return to the domestic production base if natural gas costs
merely decline. It is likely that the relative price structure of natural gas would have to invert
before the firm decided to return to producing in the domestic economy. Although U.S. natural
gas prices have risen and fallen over time, the North American market has been, and remains, a
relatively high cost region.
Table 6 shows the extent of the decline in industrial consumption of natural gas in the United
States since 1997.
Table 6. U.S. Industrial Consumption of Natural Gas
(in billions of cubic feet per year)
1997
1998
1999
2000
2001
2002
2003
2004
2005
8,511
8,320
8,079
8,142
7,344
7,507
7,150
7,250
6,608
Source: Energy Information Administration, available at http://www.eia.doe.gov.
Industrial consumption of natural gas in the United States has declined by a total of 22% over the
period 1997 to 2005. This decline may have been accompanied by a decline in U.S. jobs and tax
base, and an increase in imports of the associated mined and manufactured goods. For the first
seven months of 2006, industrial consumption of natural gas fell by 5.2% compared to the same
period in 2005.
The period August to December, 2005 was one of high natural gas prices for industrial
consumers: $7.93 per mcf in August, $10.11 per mcf in September, $11.94 per mcf in October,
the year’s peak of $12.00 per mcf in November, and $10.98 per mcf in December, followed by
high but moderating prices through 2006.
Table 7 shows the natural gas prices paid by electric power generators in 2006 compared to
2005. The period August to December, 2005 was also one of high natural gas prices for electric
power generators: $8.59 per mcf in August, $10.94 per mcf in September, the year’s peak of
$11.88 per mcf in October, $9.82 per mcf in November, and $11.33 per mcf in December.
Although this price pattern is similar to that observed in the industrial sector the effects are likely
to be different.
Congressional Research Service
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Natural Gas Markets in 2006
Table 7. U.S. Electric Power Generator Natural Gas Price
(in dollars per mcf)
January
February
March
April
May
June
July
2005
6.61
6.41
6.82
7.25
6.81
7.07
7.55
2006
9.09
7.99
7.34
7.28
6.84
NA
NA
Source: Energy Information Administration, available at http://www.eia.doe.gov.
The demand for natural gas by electric power generators is a derived demand, dependent on
electricity demand in the short term, and dependent on investment in generating capacity and
technology in the longer term. Consumers are likely to have an inelastic demand for electricity in
the short term.9 This insensitivity of electric power demand translates into an insensitivity in
generators demand for natural gas to produce the electric power.10 Electric power generators, to
the extent that market forces are able to work in the market, are likely to be able to pass cost
increases on to consumers. Electric power generators are also not as readily subject to the
possible entry of new foreign competitors into the market as a result of cost differentials, nor can
they move their production facilities outside the North American region.
In the longer term, electric power capacity investment decisions could be determined by the price
of natural gas that electric power generators face. If the relative price of natural gas increases
sufficiently, new capacity in the form of coal fired power plants could become an economically
viable competitor to gas, even though coal is not as clean burning as natural gas and requires
higher emission control expenditures.
In summary, price increases in the natural gas market have likely had an effect on the relative
demand structure for natural gas. While most sectors (e.g. residential, commercial, and electric
power generators) are likely to exhibit inelastic demand, which supports their consumption in
times of rising prices, the industrial sector has greater price sensitivity to natural gas price
increases and reduces its consumption in the face of higher prices. As a result, the aggregate
decline in U.S. natural gas consumption only gives a partial picture of the effect of high prices.
Short-Term Forecast
The EIA projects a tightening natural gas market in 2007. Aggregate consumption is expected to
increase by 2.9% compared to 2006. Residential and industrial consumption are expected to
increase by 8.7% and 2.7%. Consumption by electric power generators is expected to decline by
2.3% from 2006 levels.
U.S. production of natural gas is projected to increase by 0.8% in 2007 as the disruptions in
production due to hurricanes Katrina and Rita are repaired. Imports of LNG from Africa are
expected to rise by 41% in 2007.
9
Elasticity is a concept used to measure the sensitivity of the relationship between price and consumption. Demand is
said to be inelastic when a specified percentage change in price leads to a smaller percentage change in demand.
10
Inelastic consumer demand for electricity is thought to exist because consumers consider electricity to be an essential
good, its price per unit is low relative to income, and because of a lack of real time information consumers may not be
aware of the cost implications of their electricity consumption decisions.
Congressional Research Service
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Natural Gas Markets in 2006
Risk Factors
Analyses in this report are consistent with the EIA base case in the STEWFO, that consumers
might expect to see lower natural gas prices and heating costs during the winter 2006-2007
heating season. However, the EIA’s projection is dependent on conditions which may, or may not,
materialize. This section of the report analyzes risk factors in the 2006-2007 market outlook.
Weather
Weather is a key factor in determining natural gas consumption in the residential and commercial
sectors, and to a lesser extent in the electric power sector. The industrial sector generally is
unaffected by weather.
The EIA STEWFO baseline weather case is from the National Oceanic Atmosphere
Administration (NOAA), and assumes a winter that is 5.9% colder compared to last winter, but
2.1% warmer than the average from 1971 to 2000. Periods of cold weather can have effects on
natural gas prices. For example, it was reported that November 2006 natural gas future prices
rallied on the news of a cold weather pattern that developed in late October, even though gas
storage was approaching an all-time high level, and most analysts saw downward pressure on
price.11 If the NOAA weather forecast significantly overestimates the average temperatures this
coming winter, natural gas prices could move upward.
Oil Prices
Recent research carried out by the EIA finds that there is a significant relationship between oil
prices, measured by the West Texas Intermediate (WTI) crude oil price and the price of natural
gas at the Henry Hub. The researchers found that a one-month, temporary, increase in the price of
WTI of 20% leads to a 5% contemporaneous increase in natural gas prices, which declines to 2%
in two months. If the 20% price increase of WTI is permanent, this is found to lead to a 16%
increase in Henry Hub natural gas one year out.12
The WTI crude oil spot price reached its 2006 peak of $74.41 per barrel in July. By September
2006, the price had declined to $63.80 per barrel, a decline of over 14%. This decline in oil prices
likely contributed to the declining prices in the natural gas market. However, a contributor to the
decline in oil prices was thought to be the lessening of political tensions in the Middle East
following the withdrawal of Israeli forces from Lebanon, and the potential for a decline in
tensions with the Iranian government concerning nuclear weapons development. As in the
past, the Middle East and the Persian Gulf regions remain politically volatile, making volatile oil
prices likely.
11
Lammey, Alan, “Analysts Fear Gas Prices Have Peaked for Winter After Cold Snap,” Oil Daily, Vol. 56, No. 203,
October 23, 2006, p. 2.
12
Villar, Jose A., and Joutz, Frederick L., The Relationship Between Crude Oil and Natural Gas Prices, Energy
Information Administration, Office of Oil and Gas, October 2006.
Congressional Research Service
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Natural Gas Markets in 2006
Futures Markets
Although the effect of futures prices for natural gas traded on the NYMEX on commodity prices
traded on the Henry Hub is uncertain, an increased interest in long positions by financial traders
is likely to affect the futures price of natural gas.13 Depending on the perspective, an increasing
long position by traders could translate into an increasing price for natural gas consumers.14
However, in late October, it was reported that the market was “over-bought” and it was more
likely that a sell-off might emerge and put further downward pressure on the natural gas price.15
Conclusion
The EIA STEWFO’s conclusion that residential consumers might expect to see reduced natural
gas heating costs during the winter of 2006-2007 sees consumption rising, but price falling by a
greater proportion. Indeed, some analysts see the price of natural gas already having peaked for
the winter season. The market fundamentals of consumption, production and storage reserves are
likely to be consistent with a weakening market price. However, a contributor to the overall
reduced consumption in the market is falling industrial consumption.
Because the natural gas price has been so volatile in recent years there is a chance that the
STEWFO has over or underestimated the natural gas price for the winter heating season.
Author Contact Information
(name redacted)
Specialist in Energy Economics
-redacted-@crs.loc.gov, 7-....
13
A long position is one where the trader owns the right to buy the commodity in the future, contrasted to a short
position where the trader has the right to sell the commodity in the future.
14
See Energy Information Administration, Office of Oil and Gas, An Assessment of Prices of Natural Gas Futures
Contracts As A Predictor of Realized Spot Prices at the Henry Hub, October 2005. The EIA found that futures prices
are poor predictors of realized spot prices for any given month, and that futures prices are relatively poor at anticipating
realized spot prices.
15
Lammey, Alan, op. cit.
Congressional Research Service
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