Natural Gas Year-In-Review 2009
Natural Gas Year-In-Review 2009 Released: July 2010
Next Release: July 2011
This report provides an overview of the natural gas industry and markets in the United States in 2009 with special focus on the first complete set of supply and disposition data for 2009 from the Energy Information Administration (EIA). All data for 2009 should be considered preliminary and, unless otherwise noted, are derived from weekly and monthly EIA products. Final data for 2009 will be published in the Natural Gas Annual 2009, which is scheduled to be released in December 2010. Questions or comments should be directed to Katie Teller at email@example.com or (202) 586-6201.
Consumption Total natural gas consumption fell to 62.6 billion cubic feet (Bcf) per day, a drop of about 2 percent from the previous year's level, with year-over-year consumption declining in the residential, commercial, and industrial sectors.
The weakened state of the economy and somewhat warmer-than-normal winter weather, as measured by heating degree-days, were responsible for the drop in consumption.
Prices Natural gas prices in 2009 fell to their lowest level in 7 years. The wellhead price averaged $3.71 per thousand cubic feet (Mcf) during 2009, compared with $7.96 per Mcf in 2008.
Factors that contributed to the decline in prices were the weakened economy, reduced heating demand, as well as higher than usual production and storage levels.
Production Marketed production of natural gas averaged almost 60 Bcf per day in 2009, or a total of 21.9 trillion cubic feet (Tcf) over the year, the highest level since 1973.
Natural gas rotary rig counts averaged 801 in 2009, which was substantially lower than their record-setting average of 1,491 in 2008. Despite the reduction in rig counts and prices, production remained strong throughout the year, primarily as a result of increasing shale production and recent past investments.
Resources and Reserves EIA's Annual Energy Outlook 2010 includes estimates for total technically recoverable natural gas resources in the United States as of January 1, 2008 at 2,119 Tcf. This estimate includes proved reserves, inferred reserves, and undiscovered technically recoverable resources.
The Colorado School of Mines Potential Gas Committee (PGC) in a biennial report in June 2009 estimated the technically recoverable natural gas resource base was 2,074 Tcf as of the end of 2008.
roved reserves of natural gas have grown significantly over the past several years, further indicating an expanding resource base. The Annual Energy Outlook 2010 includes an estimate of 347 Tcf for unproved technically recoverable shale gas.
Storage At the end of November 2009, working natural gas in storage in the lower 48 States hit its highest monthly level on record at 3,833 Bcf.
During 2009, additions to storage continued past the official close of the injection season, with a net injection occurring each week in November 2009.
Imports and Exports In 2009, net imports hit a 15-year low of 2,677 Bcf, largely because of a decline in pipeline imports from Canada.
Liquefied natural gas (LNG) imports in 2009 rose from the previous year's level of 352 Bcf to 452 Bcf. However, this total was still the second-lowest level of annual LNG imports in 7 years.
Pipeline Construction Additions to the national pipeline grid totaled close to 3,000 miles in 2009, representing an investment of about $9.9 billion spread across about 43 natural gas pipeline projects.
The largest natural gas pipeline project completed in 2009 was the 639-mile Rockies Express-East (REX-East) pipeline system.
Overview In 2009, relatively abundant supply and low prices characterized natural gas markets. The combined impact of weak natural gas demand - evident in the commercial and industrial sectors - due to the economic downturn and continued strong domestic natural gas production likely contributed to the decline in prices compared with 2008 levels. The reduction in consumption in the commercial and industrial sectors, however, was offset somewhat by increases in the use of natural gas for electric power generation. Henry Hub prices in 2009 averaged $4.06 per Mcf, compared with $9.12 per Mcf in 2008. Natural gas prices across most sectors spiked during the first 8 months of the recession, which officially began in December 2007.1 However, prices began falling in the latter half of 2008, and have mostly continued to weaken since then (see Figure 1).
Despite lower prices in 2009 than in 2008 and fewer rig counts, natural gas production remained robust, possibly adding to downward pressure on prices. Past investments in more efficient means of production buoyed production levels. Additionally, the correlation typically observed between the natural gas rig count, prices, and production became less evident, illustrating the impact of the increasing presence of production of natural gas from shale formations, horizontal drilling, and hydraulic fracturing. While these production methods are not particularly new, they have become more efficient and more widespread in the last few years. For example, horizontal rig counts have increased relative to vertical rig counts.2 Horizontal drilling tends to produce more natural gas per well and result in higher initial production rates.3 In addition, operators have been drilling longer laterals (the horizontal lines that permeate gas-bearing rock) for horizontal wells, further increasing production.
Source: Energy Information Administration, Natural Gas Monthly (April 2010).
The Weakened Economy Dampened Commercial and Industrial Consumption Even with lower natural gas prices, natural gas consumption declined from the previous year in the residential, commercial, and industrial sectors due to a combination of weather and economic factors. Weather was the primary factor contributing to lower residential consumption; while the weakened economy was a major influence in declines in commercial and industrial consumption. Gains in consumption from electric power from partially offset losses in the other sectors. Total U.S. consumption fell to 62.6 Bcf per day in 2009, from 63.6 Bcf per day in 2008. Consumption in the commercial sector fell about 1 percent, from 8.6 Bcf per day to 8.5 Bcf per day. In the industrial sector, consumption fell 8 percent from 18.2 Bcf per day in 2008 to 16.8 Bcf per day in 2009. Industrial natural gas consumption in 2009 was about 9 percent lower than the 5-year (2004-2008) average level of 18.4 Bcf per day. Notably, activity in the manufacturing sector slowed in 2009, according to data from the Federal Reserve Board. The Federal Reserve's Index of Industrial Production shows industrial activity in 2009 decreased relative to past years. Also, the Federal Reserve's measure of capacity utilization showed that the nation's factories were operating at a 70.4-percent rate in 2009, down from 77.5 percent in 2008.
Over the long term, appliance efficiency gains and improved housing construction have resulted in a significant decrease in the volume of natural gas used by households in the United States, with per customer consumption falling in 16 out of the past 19 years. On a weather-adjusted basis, residential consumption over the 19-year period fell from 95 thousand cubic feet (Mcf) per customer in 1990 to 74 Mcf in 2009, or 22 percent.
Total residential natural gas consumption declined from 13.3 Bcf per day in 2008 to 13.0 Bcf per day in 2009, due in part to average heating season temperatures in 2009 that were warmer than both the 30-year normal level and the previous year. Despite the overall pattern of somewhat warmer-than-normal temperatures, exceptionally cold weather led to unusually high natural gas consumption during two months in 2009. Residential consumption in October was almost 16 percent higher than the year-ago level of 6.9 Bcf per day, and 18 percent higher than the 5-year (2004-2008) October average of 6.8 Bcf per day. Similarly, a cold January 2009 pushed residential consumption again above the 5-year average. In contrast, temperatures warmer than the 30-year average in February and November reduced consumption.
On the other hand, consumption of natural gas for electric power increased from its 2008 level of 18.3 Bcf per day to 18.9 Bcf per day in 2009. This increase was driven by fuel-switching due to sharp declines in the price of natural gas as coal prices actually rose between 2008 and 2009 while consumption of coal at electric power plants declined 11 percent.4 During the summer of 2008, natural gas prices spiked to high levels, but fell near the end of the year and remained relatively low in 2009. The cost of natural-gas fired generation also fell, becoming cheaper than generation using some coal-fired power plants in some areas. As a result, when natural gas prices fell, power generators increased their utilization of existing natural gas-fired generation capacity more intensively.
Over the past several years, natural gas use for electric power has increased, with gas making up an increasing percentage share of total generation relative to coal. In 2009, natural gas made up almost 24 percent of net power generation with 931,000 Megawatt-hours (MWH) of electric power generated from natural gas. By comparison, in 1996, natural gas made up only 14 percent of power generation.5 Conversely, coal fell from 50 percent of generation in 1995 to 45 percent in 2009. Consumption of natural gas for electric power is generally higher in the summer, when demand for air-conditioning is rises. (Figure 2)
Source: Energy Information Administration, Short-Term Energy Outlook (April 2010), National Weather Service
Natural Gas Prices Moderated From Unusually High Levels in 2008 Average monthly wellhead and spot natural gas prices moderated in 2009 from historically high 2008 levels. During the year, natural gas prices stayed within a much smaller range than they did in 2008.6 Monthly average wellhead prices in 2008 peaked at $11.32 per Mcf in July, and fell to their yearly minimum of $4.75 in November, a range of $6.67. However, in 2009, the maximum average monthly price was $5.15 per Mcf in January, while the minimum was $2.92 per Mcf in September, a range of $2.23. In the 5 years prior to 2008 (2003-2007), this range averaged $2.60 per Mcf.
Retail prices fell in all sectors, with declines ranging from 14 percent to 47 percent. The most notable drops occurred in electric power and industrial prices, at 47 percent and 46 percent, respectively. With a yearly average of $5.27 per Mcf, industrial natural gas prices were at their lowest since 2002. Prices in all other end-use sectors were also lower in 2009 than in previous recent years. Residential prices fell 14 percent from $13.89 per Mcf in 2008 to $11.97 per Mcf in 2009. Over the same period, commercial prices dropped 20 percent from $12.23 per Mcf to $9.75 per Mcf.
During the year, Henry Hub spot prices averaged $4.06 per Mcf, down from $9.12 per Mcf in 2008. In 2009, the average annual spot price at the Henry Hub was at its lowest level since 2002. On September 4, the Henry Hub spot price finished trading at $1.79 per Mcf, its lowest level in 9 years, before recovering over subsequent weeks.
Production Remained Robust in 2009 In 2009, marketed production of natural gas reached 21.9 trillion cubic feet (Tcf), its highest recorded annual total since 1973. Production of natural gas from shale and tight sand formations continued to increase. The increases in production were the result of more efficient, cost-effective drilling techniques, notably in the production of natural gas from shale formations.7 Additionally, shale gas has been the primary source of recent growth in United States technically recoverable natural gas resources.8 Natural gas production remained robust throughout the year, as the lack of any significant hurricane activity resulted in minimal production losses. Hurricane Ida occurred very late in the season (November 9, 2009), and resulted in total production shut-ins of only 4.6 Bcf (Figure 3). Relatively low production in September may have been the result of relatively low prices during the late summer.
Source: Energy Information Administration, Natural Gas Monthly (April 2010)
In previous years, the natural gas rotary rig count, as reported by Baker Hughes Incorporated, usually lagged the Henry Hub natural gas price by several weeks or more. This relationship became less apparent in the second part of 2009. The rig count fell to a low of 665 on July 17, marking the lowest level since 2002, before recovering to 759 on December 31. (Figure 4). Despite the low number of active rigs, production continued to be robust in 2009, demonstrating continued efficiency gains over the years. This development was facilitated by technological advances in drilling and well-completion techniques.
Also bolstering production is an increase in resources and reserves, particularly shale gas. EIA's Annual Energy Outlook 2010 (AEO2010) includes estimates of unproved technically recoverable natural gas shale resources at 347 trillion cubic feet; in the AEO2009 they were estimated at 267 trillion cubic feet. Proved reserves of natural gas have continued to grow over the past several years, further indicating an expanding resource base. At the end of 2008, proved reserves of dry natural gas were estimated at 245 Tcf, increasing for the 10th consecutive year.
Sources: Rig Count Data: Baker Hughes Incorporated; Henry Hub Price: Natural Gas Intelligence's Daily Gas Price Index
Working Gas Storage Inventories Set Records During the 2008-2009 heating season (November 2008 - March 2009), working gas storage inventories set records on a national level, as well as in each of the three storage regions. The heating season began with 3,399 Bcf in storage. Withdrawals totaled 1,743 Bcf, leaving inventories at 1,656 Bcf by the end of March. At the official end of the 2009 injection season (April 1- October 31, 2009), inventories reached 3,807 Bcf. Storage levels at the end of October 2009 surpassed the previous record-high of 3,565 Bcf, set in October 2007. According to an EIA analysis, estimated peak working gas capacity increased in 2009 from the previous year, to 3,889 Bcf, from 3,789 Bcf in 2008. Design capacity also increased.9 Injections continued throughout November, with working gas inventories reaching 3,833 Bcf by the end of the month. In fact, 2009 was the first year since 2001 in which a net injection occurred each week of November.
Monthly storage levels in 2009 exceeded the 5-year average (2004-2008) levels for each month of the year (Figure 5). Working gas stocks in the lower 48 States totaled about 99 percent of the estimated peak storage capacity of 3,889 Bcf.10 On a regional basis, working gas in storage reached an all-time high in November in the Producing and West regions, at 1,224 Bcf and 524 Bcf, respectively. The East Region reached an all-time high in October, at 2,097 Bcf (Figure 6). Additionally, the November levels in the Producing and West region slightly exceeded the estimated peak capacity,11 while the end-of-October levels in the East came to about 96 percent of peak capacity. However, by the end of the year, the surpluses had eroded somewhat and inventories moved closer to the 5-year average in all regions. In the Producing region, the differential between 2009 levels and the 5-year average was higher than in the East and West regions, due in part to the influence of salt cavern additions to storage in the region.
Reasons for the unprecedented end-of-November levels were numerous. The increases in design capacity as well as robust production may have played a role. Additionally, inventories started off the injection season at 1,656 Bcf, which far exceeded the average of 2004-2008 of 1,381 Bcf. Pricing patterns also may have provided incentives for storage injections. For example, when natural gas futures prices are substantially higher than spot prices, storage operators have an incentive to put gas into storage and profit from its sale at a later date. Specifically, near the end of the injection season, the price differential between the New York Mercantile Exchange near-month contract price and the Henry Hub spot contract price was highest in October and November, averaging 77 cents and 92 cents respectively. In November of 2008, on the other hand, the near-month contract only averaged about 1 cent higher than the spot contract, with much variation between a positive and negative differential during individual trading days. The price differential was present during much of the rest of 2009, but was not quite as strong as it was in October and November.
Source: Energy Information Administration, Natural Gas Monthly (March 2010)
Source: Energy Information Administration, Natural Gas Monthly (March 2010)
Net Imports Hit a 15-Year Low; LNG Imports Rose from 2008 Levels Pipeline Imports from Canada Fell Sharply
In 2009, net imports to the United States reached a 15-year low of 2,677 Bcf, a decrease of about 302 Bcf, or 10.1 percent, from the previous year (Figure 7). The volume of net imports in 2009 equaled about 12 percent of U.S. natural gas consumption, which was the lowest ratio since 1994. A significant decline in pipeline imports from Canada was the largest single factor contributing to the decrease, as gross imports from the country decreased 321 Bcf or 9.0 percent in 2009 compared with 2008, while exports to Canada from the U.S. increased. Canada continued to be the largest source country for gross natural gas imports to the United States, accounting for 87 percent of the 2009 total. At the same time pipeline imports from both Canada and Mexico fell, liquefied natural gas (LNG) imports increased, rising from 12 percent of net imports in 2008 to 17 percent in 2009.
Source: U.S. Department of Energy, Office of Fossil Energy
Reduced output in the Western Canada Sedimentary Basin has played a role in the decline of deliveries to the United States. Conventional gas production in Canada has been on the decline since about 2005. While activity and production in Canada is increasing in unconventional areas such as shale plays, the growth has been much slower than in the United States.
Exports to Canada Increased Year to Year Total natural gas exports out of the U.S. increased by 7 percent from 2008 to 2009 to a historical high of 1.1 Tcf, despite decreases in volumes to Mexico and Japan. U.S. exports to Canada, which occur primarily through Vector Pipeline from the Chicago area into Ontario, were 109 Bcf higher than in 2008, a 19 percent increase. During the year, pipeline capacity and associated supply options expanded in the Upper Midwest. In 2009 Canada represented 65 percent of total natural gas exported out of the United States.
Net U.S. exports to Mexico decreased to 310 Bcf, a decline of 3.7 percent from 2008. The decline in U.S. exports followed notable production gains by State-controlled Petróleos Mexicanos (PEMEX) in the last couple of years, as well as growth in LNG-receipt capacity. Mexico now has two operating LNG terminals, one on the east coast which has been in operation since 2006 and one on the west coast which recently went into service, and received a combined total of approximately 126 Bcf during 2009. In each of the last 5 years, U.S. export volumes to Mexico were considerably lower than the historical high of 397 Bcf reached in 2004.
LNG exports to Japan declined by a third in 2009 due to gas production declines in the Kenai region. The export license for Nikiski liquefaction facility in Kenai, Alaska expires in March of 2011. Export volumes over the last three years have been significantly reduced from previous levels. The owners of the facility have filed to extend the license for two more years.
LNG Imports Rose from 2008, But Remained Relatively Low
Imports of LNG to the continental United States in 2009 rose 29 percent, or 100 Bcf, to a total of 452 Bcf but were still the second-lowest annual level in 8 years. Despite the overall increase in LNG imports compared with 2008, which represented a 5-year low, total volumes in 2009 were still well below the record of 771 Bcf in 2007, as higher prices for natural gas in other countries have diverted volumes away from the U.S. market, particularly during high-demand periods leading up to and during the winter months. Although LNG imports have substantially increased since early this decade, progress has been uneven from year to year.
In 2009, U.S. imports of LNG averaged 1.2 Bcf per day - about 11 percent of the sendout capacity at U.S. regasification terminals, which is usually expressed as the capability of the terminals to send out regasified LNG into the pipeline grid. (Figure 8). Distrigas Corporation's regasification facility in Everett, Massachusetts, operated at the highest level of utilization during the year at about 60 percent. This was because Everett received the greatest volume of LNG deliveries of any of the 9 import facilities operating during the year, with receipts totaling 156 Bcf, primarily from Trinidad and Tobago. El Paso Corporation's terminal on Elba Island, Georgia, received 142 Bcf, the second-highest volume received by the terminals.
Source: Energy Information Administration, U.S. Department of Energy, Office of Fossil Energy.
Five countries supplied U.S. LNG imports in 2009: Trinidad and Tobago, Egypt, Norway, Nigeria, and Qatar. Although imports from Trinidad and Tobago decreased by 11 percent to 236 Bcf, the country remained the largest exporter to the United States. The source countries for the second and third largest 2009 LNG import volumes were Egypt and Norway, respectively, both of which supplied record high import volumes in the year and nearly tripled and doubled their respective import volumes from 2008. (Figure 9)
LNG imports to the United States were highest from April to June. Demand for natural gas begins to wane in other areas of the world around this time, freeing up cargoes to come to the United States.
Additionally, in 2009, three companies received authority to re-export imported LNG from import terminals in the United States. Only one re-exported shipment occurred during the year.
Source: U.S. Department of Energy, Office of Fossil Energy.
Pipeline Expansions Were Substantially Less Than in 2008 Pipeline construction activity in 2009 was substantial, but declined from the exceptionally high pace of additions in 2008, when close to 4,000 miles were added to the pipeline grid. At least 43 natural gas pipeline projects were completed in 2009 in the lower 48 States, substantially less than the record 84 projects completed in 2008. Nonetheless, these projects added close to 2,988 miles of pipeline to the national natural gas pipeline grid and represented investment of about $9.9 billion. (Figure 10).
Source: Energy Information Administration, GasTran Natural Gas Transportation Information System.
The Rockies Express Pipeline Gave Western Producers Improved Access to Eastern Markets
In terms of added miles, the largest natural gas pipeline project completed in 2009 was the 639-mile Rockies Express-East (REX-East) pipeline system. The completion of REX-East extension in November 2009 marked the end of the construction of the entire REX pipeline, which stretches 1,679 miles from Rio Blanco County, Colorado, to Monroe County, Ohio. (Figure 11)
Rockies producers now have direct access to eastern markets for the first time. In total, the pipeline interconnects with more than 25 intrastate and interstate pipelines transporting natural gas from the Gulf of Mexico region and from the Midcontinent. The impact of these interconnections has been greater price competition among supply basins in North America. REX is a joint partnership of Kinder Morgan Energy Partners, L.P., Sempra Energy, and Conoco, Inc. The cost of constructing REX-East, which has a 42-inch diameter and a capacity of 1.8 Bcf per day, was $2.2 billion.
The Midcontinent Express Allowed for More Deliverability from the Barnett Shale
The new Midcontinent Express Pipeline (MEP), completed in July 2009, has proven to be another major infrastructure project that is affecting regional flow patterns. The pipeline, a joint venture between Kinder Morgan Energy Partners, L.P. and Energy Transfer Partners, L.P., extends 506 miles from the southeast corner of Oklahoma, across northeast Texas, northern Louisiana, central Mississippi and into Alabama, interconnecting with numerous major pipeline systems.
The direction of flows on the pipeline (from Oklahoma and Texas to Florida) allows greater deliverability from supply areas such as the Barnett Shale and access to high-demand eastern U.S. markets. The pipeline currently has a capacity of 1.4 Bcf per day, which will increase to 1.8 Bcf per day following the expansion planned for 2010.
As in the past several years, the need for increased access to growing supplies from shale deposits continued to drive pipeline construction during 2009. The push for access to new shale deposits has led to rapid infrastructure growth in northeastern Texas, as well as in Arkansas and Mississippi. Several projects were constructed to continue the flow of natural gas from the Barnett Shale to regional markets.
Energy Transfer Company in August 2009 completed its Texas Independence project, which in total is one of the larger infrastructure projects constructed in northeastern Texas in recent years. The 160-mile pipeline, construction of which costs $85 million, extends across Texas and connects Energy Transfer's existing central and north Texas infrastructure to its east Texas pipeline network.
Source: Energy Information Administration, GasTran Natural Gas Transportation Information System.
1 The National Bureau of Economic Research (NBER), a private research organization that provides start and end dates to recessions in the United States, announced in late 2008 that the United States economy had been in recession since December 2007. As of the date of the publication of this report, the NBER has not yet announced the end date to this recession.
2 Hydraulic fracturing is defined as fracturing of rock at depth with fluid pressure. Hydraulic fracturing at depth may be accomplished by pumping water into a well at very high pressures.
3 More information about horizontal drilling is available here: http://www.fossil.energy.gov/programs/oilgas/publications/environ_benefits/6drill.pdf
4 Energy Information Administration, Electric Power Monthly, DOE/EIA-0225 (2010/03) (Washington, DC, March 2010), Tables ES1.B and 1.1.
6 Range in this instance is defined as maximum minus minimum monthly price. Price data are from EIA's Natural Gas Navigator.
7 According to the AEO2010 Early Release, production of natural gas from shale formations increased from 1.15 Tcf in 2007 to 1.49 Tcf in 2008. Though data are not available yet for 2009, the AEO projects that shale gas will account for 3.85 Tcf of production in 2015 and increase to 6 Tcf by 2035. This reflects an annual growth rate of 5.3 percent and accounts for the majority of growth in natural gas supply.
8AEO2010 Early Release Summary Presentation.
9 EIA published estimates of peak underground working gas storage capacity as of April 2009 in Estimates of Peak Underground Working Gas Storage Capacity in the United States, 2009 Update.
11 The estimate of peak capacity is based on demonstrated noncoincident peak working gas storage volumes for individual active gas storage fields reported to EIA over the 60-month period ending in April 2009.
Energy Information Administration (EIA)