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Natural Gas Year-In-Review 2008            
Released: April 2009   
Next Release: April 2010

This report provides an overview of the natural gas industry and markets in 2008 with special focus on the first complete set of supply and disposition data for 2008 from the Energy Information Administration (EIA). All data for 2008 should be considered preliminary, and unless otherwise noted, data are derived from weekly and monthly EIA products. In certain cases data for all 12 months of 2008 are not yet available, so analysis is based on cumulative totals as indicated in the text. Final data for 2008 will be released in the Natural Gas Annual 2008, which is scheduled to be released in December 2009. Questions or comments should be directed to Katie Teller at katherine.teller@eia.doe.gov or (202) 586-6201
  Consumption in 2008 reached 23.2 trillion cubic feet (Tcf), a near-record level, second only to the volume consumed in 2000.
  Natural gas consumption increased slightly from 2007 levels, likely because of an increase in heating degree-days.  
Natural Gas Markets
  Natural gas wellhead prices exhibited a counter-seasonal trend, hitting their peak in mid-year, following the same pattern as many other commodity prices.
  In contrast to high price spikes in the aftermath of Hurricanes Katrina and Rita in 2005, natural gas prices showed little response to Hurricanes Gustav and Ike and continued to slide through the end of the year.
  Cumulative hurricane-related production shut-ins in the Federal offshore Gulf of Mexico and onshore and State waters of Louisiana exceeded 400 billion cubic feet (Bcf) from early September through the end of the year.
  Working gas in storage exceeded the 5-year (2003-2007) average in the latter half of 2008 despite hurricane-related production disruptions and low liquefied natural gas (LNG) imports.
Pipeline Construction
  During 2008, at least 84 natural gas pipeline projects were completed in the Lower-48 States, adding close to 4,000 miles of natural gas pipeline and about 43.9 Bcf per day of new capacity to the national natural gas pipeline grid.
Imports and Exports
  Net natural gas imports from all sources were at their lowest level since 1997.
  LNG imports fell 54 percent from the 2007 level to 352 Bcf.
  Three new LNG terminals opened, including the first new onshore terminal in more than 25 years.


Following the general pattern of oil, natural gas prices spiked in the summer and fell in the winter in 2008. This pattern is in contrast to normal seasonal patterns of natural gas prices rising in the winter and falling in the summer. Most natural gas prices spiked in the summer of 2008 after about a year-long upward climb (Figure 1). Wellhead prices averaged $5.87 per thousand cubic feet (Mcf) in December 2008, a 46 percent drop from their June 2008 level of 10.8 per Mcf. In 2008, seasonal weather was not as strong an influence in driving natural gas prices as it has been in the past.

Weather played an important role in natural gas consumption and production in the Gulf of Mexico and Louisiana. Hurricanes Gustav and Ike hit the Gulf Coast in September, creating cumulative production shut-ins estimated at 413.6 Bcf through the end of 2008. Natural gas storage remained below record-setting 2007 levels, yet exceeded the 5-year (2003-2007) average during the latter half of 2008.

Figure 1. Natural Gas Prices Rose, then Fell as the Economy Weakened
Source: Energy Information Administration, Office of Oil and Gas.   Figure Data


Consumption for the year increased to near-record levels

At 23.2 Tcf, consumption in 2008 was at a near-record level, second only to the 23.3 Tcf consumed in 2000. Total consumption in the United States increased by about 0.1 percent over the 2007 level. Overall, 2008 had 5.6 percent more heating degree-days than 2007. Winter temperatures in 2008 were colder than their 2007 levels, although temperatures in 2008 were warmer than the 30-year average (Figure 2). The near-record levels occurred in spite of downward pressures on consumption, such as hurricane activity and a weakened economy. 2008 is the second consecutive year consumption has increased after decreasing in 2005 and 2006.

Consumption of natural gas for electric power ranged from a 19-percent year-over-year increase in January to a 24-percent year-over-year decrease in August. Residential consumption also displayed wide swings, with 10 and 9 percent year-over-year increases in January and February, respectively, resulting in a cumulative increase of 3 percent for the year.

Although consumption was slightly above 2007 levels for most of 2008, the price spikes during the summer, as well as mild temperatures in August 2008, caused consumption to drop dramatically in these months. The August 2007 total consumption was 1.89 Tcf, while August 2008 levels were 1.69 Tcf. This disparity represents about a 12-percent year-over-year decline. Natural gas use for electric power generation declined 24 percent year-over-year from August 2007 to August 2008, reflecting the cooling degree-day decline of 23 percent year-over-year.

While monthly residential and commercial natural gas consumption was close to or slightly above 2007 levels as well as the average level for 2003-2007, monthly industrial consumption in 2008 was below its 2003-2007 average levels for most of the year.

Figure 2. Temperatures in 2008 Were Warmer Than the 30-Year Average
Note: Temperatures are warmer than normal in months when the deviations from normal are negative for heating degree-days and positive for cooling degree-days.
Source: Degree-day data provided by EIA’s Short-Term Energy Outlook, data derived from National Oceanic and Atmospheric Administration. Normal temperatures represent a 30-year average over 1970-2001.   Figure Data

Natural gas for electric power generation remained a key use of natural gas
In 2008 electric power sector natural gas consumption was a large share of the total deliveries to consumers, which includes the residential, commercial, industrial and electric power sectors. After a slight decline in the relative consumption of natural gas for electric power generation, natural gas for electric power still made up 31 percent of delivered volumes for 2008, compared with 25 percent in 2003 (Figure 3). Industrial consumption also was 31 percent of the total, but it has displayed a general downward trend over the past 5 years. Although residential consumption increased slightly over the past 2 years, it has shrunk overall from 25 percent in 2003 to 23 percent in 2008. Natural gas for vehicle fuel has increased over the past several years but remains at less than 1 percent of the total.

Figure 3. Electric Power Made Up 31 Percent of Natural Gas Consumption, Despite a Slight Decline from 2007
Note: Percentages are based on total deliveries to consumers. The share of natural gas end use deliveries for
vehicle use is not shown because it is less than 1 percent.
Source: Energy Information Administration, Office of Oil and Gas.   Figure Data

Effects of Hurricanes Gustav and Ike caused lower consumption
Hurricane activity also influenced natural gas consumption in late summer as the South experienced widespread power outages. In September, total U.S. natural gas volumes fell 14 percent from the previous month and 8 percent from September 2007. This decrease is mostly the result of hurricane production shut-ins, as electric power service was interrupted for 3.7 million customers, and 25 percent of Texas customers’ power was interrupted in mid-September1. However, weather played a role in the year-over-year declines in natural gas consumption for electric power generation in other ways, as cooling degree-days were 11 percent less than the previous year. A number of States posted large year-over-year declines in natural gas consumption for power generation. Overall, natural gas consumption for electric power fell 21 percent from August to September. Texas is the top consuming State for natural-gas-fired electric power and drops in consumption in this State accounted for roughly one-third of the decline in total natural gas used for power generation from August to September. Additionally, 84 percent of the drop in industrial consumption, which fell 11 percent from the previous month, was the direct result of consumption decreases in Texas and Louisiana. The storm shut down many refineries, processing plants, and other industrial users of natural gas.



Natural gas prices rose to relatively high levels in the summer of 2008, and then declined more swiftly than they had risen after beginning a generally increasing pattern in the summer of 2007. The average wellhead price in U.S. dollars was $10.82 in June 2008, the highest nominal recorded level. Henry Hub prices spiked to $13.68 per thousand cubic feet on July 2, 2008.2

After slight upturns in the days around landfall of Hurricanes Gustav and Ike, daily spot prices resumed their downward slide. Natural gas prices showed little response to Hurricanes Gustav and Ike and continued to slide through the end of the year, in contrast to high spot price spikes in the aftermath of Hurricanes Katrina and Rita in 2005. Growth in onshore production and robust storage inventories, as well as a declining economy, likely outweighed offshore supply disruptions created by Gustav and Ike. Additionally, compared with 2005, the 2008 storms were less powerful and thus limited their shock to the market. (Figure 4)

Figure 4. Production Declines Failed to Slow Price Declines
Source: Energy Information Administration, Office of Oil and Gas.   Figure Data

The natural gas price increase and subsequent decline mirrored patterns in oil prices. Wellhead, city gate, commercial, industrial, and electric power prices displayed similar patterns when compared year-over-year—with high increases in the summer changing to declines in the later months of 2008. For example, in July, year-over-year prices showed the highest increases across the board—up 73 percent for industrial prices.

Wellhead prices moved within a wide range in 2008
As a result of wide swings, the range in average monthly wellhead prices for the year was the widest in history.3 Wellhead prices fell by $4.95 per Mcf from the June peak of $10.82 per Mcf to an average of $5.87 per Mcf in December. Within-year variation in monthly prices is expected to be less in 2009, remaining within a $1.13 range, according to EIA’s March Short-Term Energy Outlook.4 The projected average wellhead price for all of 2009 is $4.22 per Mcf, down 48 percent from the 2008 average of $8.08.

Despite a wide price range, price volatility moderated during the year
Daily price volatility moderated in 2008, despite the wide swings in price during the year. Volatility refers to the degree of daily relative price variation and is defined as the standard deviation of daily relative changes in price. Monthly volatility, measured using daily Henry Hub price movements, generally showed higher volatility during the heating season. However, monthly volatility overall appears to be less than in previous years. Annual volatility measured with daily Henry Hub price movements also dropped from 63 percent in 2007 to 49 percent in 2008, while average annual prices rose from $6.97 per million Btu (MMBtu) to $8.89 per MMBtu. The decline in volatility measures using daily price movements may be due to the pattern of price increases and decreases; prices did not oscillate, but moved up steadily and then fell steadily.

Monthly volatility generally continued to display seasonal patterns even as prices fell, with higher volatility in the fall and in winter months (Figure 5).

Figure 5. Volatility Continued to Display Seasonal Patterns
Source: Volatility derived by EIA Office of Oil and Gas. Henry Hub prices from Natural Gas Intelligence's Daily Gas Price Index.   Figure Data

Rockies Express changed pricing dynamics in the Midcontinent
On January 8, 2008, the western leg of the Rockies Express Pipeline came online, connecting the Rockies region with the Midcontinent region. This led to changes in pricing at key pricing points. After its opening, the 713-mile Rockies Express West (REX-West) has operated at near capacity and price differentials between the two regions have narrowed except for a period when a portion of capacity on REX-West was offline.

On September 3, 2008, REX-West began a major outage for hydrostatic testing of a portion of its mainline. The pipeline came back online at the end of September. During the month of September, prices were volatile in the Rockies region at the Opal Hub, ranging from $0.70 per MMBtu on trading day September 3, 2008, to $5.43 per MMBtu on trading day September 9.5 Low prices prevailed through most of October, likely as a result of the oversupply in the Rockies and Midcontinent.

REX-East, the third phase of REX project, will be completed in stages with transportation service expected through Lebanon, Ohio, in June 2009 and the completion of the pipeline terminus in Clarington, Ohio, by November 2009.

Overview of production

Production shut-ins affected supplies from the Gulf of Mexico
The Independence Hub, a deepwater production platform in the Gulf of Mexico, is designed to produce 1 Bcf per day of natural gas at a water depth of 8,000 feet. The Independence Hub went offline in April for repairs and did not resume full production until mid-June, producing about 900 MMcf per day.

Based on data from the U.S. Minerals Management Service and the Louisiana Department of Natural Resources, total cumulative shut-ins from Hurricanes Gustav and Ike were an estimated 413 Bcf, with losses in the Federal offshore Gulf making up about 87 percent of the total. On September 13, 2008, production shut-ins peaked at an estimated 8.0 Bcf per day. Estimated cumulative shut-ins for the final 4 months of 2008 equaled about 6 percent of total U.S. natural gas production for 2008. At the end of 2008 an estimated 1.3 Bcf per day remained shut in the Gulf, which represented about 2 percent of total United States daily marketed production in December 2008. These figures compare with an estimated cumulative 565 Bcf of natural gas that was shut in by the end of 2005 as a result of damages from Hurricanes Katrina and Rita.

Offshore production might benefit from lifting of drilling moratorium
In July 2008, Former President George W. Bush lifted the Executive Order banning drilling in large areas of the Federal Outer Continental Shelf (OCS) since 1990.6 A congressional ban on drilling in certain offshore areas also ended when Congress did not include the leasing prohibition in budget legislation beyond the fiscal year ending September 30, 2008. The effect of lifting the moratoria on oil and natural gas development and whether the Obama administration or the new Congress will place other limits on offshore development is unclear. According to the U.S. Minerals Management Service estimates, about 76 Tcf of natural gas and 18 billion barrels of oil are technically recoverable in areas in the Lower 48 Federal OCS subject to the moratoria. Even with the lifting of the moratoria, production in previously restricted areas will not occur for several years. A ban on drilling through 2022 on certain tracts near Florida in the Eastern and Central Gulf of Mexico remains in place under provisions of the Gulf of Mexico Energy Security Act of 2006. EIA’s Annual Energy Outlook 2009 (AEO) notes that there is still considerable uncertainty about development of resources on the Federal OCS, as well as uncertainty about the amount of oil and natural gas resources on the OCS. The AEO notes that the key issue affecting this will be timing, as new leases will require a lead time of at least 4 years before initial production. 7

Rig count for gas drilling rose to record highs, then fell
The natural gas rig count reached 1,606 on August 29, 2008, and again on September 12, 2008, according to data provided by Baker Hughes, Incorporated. This count represents the highest number of natural gas rigs in the more than 21 years since July 1987, when publication of drilling rig data by fuel type began.

By the end of the year, the rig count fell about 16 percent, to 1,347 for the week ended December 26, 2008. The gas rig count continued to fall in early 2009 to 760 for the week ending April 17, 2009, which is the lowest level since March 14, 2003, when natural gas rigs totaled 754. Factors likely leading to the drop in rig count from the highs in August and September include the drop in natural gas and oil prices, which weakens the incentive to drill, and the difficulty obtaining financing in a weakened economy, which may lead producers to cancel plans for drilling projects. Changes in the rig count appear to lag movements in the Henry Hub price by several weeks or more in 2008 (Figure 6).

Figure 6.The Natural Gas Rig Count Dropped from Record Highs in Late Summer
Sources: Rig Count Data: Baker Hughes, Incorporated, Henry Hub data: Intelligence Press, NGI's Daily Gas Price Index.   Figure Data

Natural gas storage levels remained strong

Natural gas in storage was below the 5-year average for the spring and summer months, but rebounded in July and remained above the 5-year average for the rest of the year, despite production shut-ins that occurred as a result of Hurricanes Gustav and Ike (Figure 7). Storage levels remained below 2007 levels, which were unusually high compared with the 2002-2006 average. The Lower-48 States ended the 2008 refill season with 3,399 Bcf in inventories.

Figure 7. Storage Levels Fell below the 5-year Average, then Recovered
Source: Energy Information Administration, Office of Oil and Natural Gas.   Figure Data

As of mid-2008 peak working natural gas storage capacity in the Lower-48 States was estimated at 3,789 Bcf, an increase of 86 Bcf from the previous year.8

Major pipeline were completed in 2008

During 2008, at least 84 natural gas pipeline projects were completed in the Lower-48 States, adding close to 4,000 miles of natural gas pipeline and about 43.9 Bcf per day of new capacity to the national natural gas pipeline grid, at an estimated expenditure of $11.6 billion. These figures represent a three-fold increase over 2007 when $4.2 billion was spent on laying 1,674 miles of new pipeline while adding 14.9 Bcf per day of new capacity to the network (Figure 8).

Figure 8. Natural Gas Pipeline Capacity Additions
Source: Energy Information Administration, GasTran Natural Gas Transportation Information System, Natural Gas Pipeline Projects Database, as of January 2009.   Figure Data

The scale of the natural gas pipeline projects completed in 2008 was also exceptional. The capacity addition for 15 of the projects exceeded 1 Bcf per day, the largest being 2.6 Bcf per day. The average added capacity per project overall was 522 million cubic feet per day compared with only 290 MMcf per day in 2007, which was the second largest construction year in the last 10 years. Moreover, the average added miles of pipeline laid (for projects with greater than 5 miles of new pipeline) were 69 miles compared with only 47 miles in 2007.

Sixty-five of the projects involved expansion of the interstate natural gas pipeline network, representing 34.2 Bcf per day of new capacity. The remaining 19 projects improved capacity and transportation service on intrastate natural gas pipelines (9.9 Bcf per day). More than one-third of the projects attempted to satisfy a growing need for additional natural gas pipeline capacity to support transportation of new natural gas production to regional markets, adding 16.3 Bcf per day of pipeline capacity overall. Such projects were concentrated in the expanding natural gas production areas of Wyoming, western Colorado, and in the Barnett shale formation of northeast Texas.

About 11 percent of all newly added natural gas pipeline capacity for 2008, or 4.6 Bcf per day, is attributable to new intrastate pipelines built to transport expanding Barnett shale production to local markets and to interconnections with the interstate natural gas pipeline network. In turn, several major interstate pipeline projects were also constructed to continue the flow of this natural gas beyond east Texas to interstate pipeline interconnections in Louisiana, Mississippi, and Alabama. These projects included the new Southeast Supply Header Pipeline (Louisiana to Mississippi), the new Gulf South Southeast Extension (Mississippi to Alabama) and the Gulf South Texas to Mississippi Expansion, which added more than 4.1 Bcf per day to the natural gas pipeline network in the Gulf Coast region.

Also found among the major natural gas pipeline additions of 2008 were several large capacity pipelines built to link the interstate natural gas pipeline network to several LNG import terminals that were newly-commissioned or expanded during the year. Such projects accounted for 10.9 Bcf per day of new natural gas pipeline capacity, or about 24 percent of total new capacity. Accounting for another 8.5 Bcf per day, or 19 percent of new pipeline capacity, were 9 major bidirectional header systems built to support new natural gas underground storage facilities.

The largest natural gas pipeline project completed in 2008, which was not associated with an LNG import or underground storage facility, was the 1.5-Bcf-per-day, 720-mile, REX Pipeline system. Commencing at the Cheyenne Hub in northeastern Colorado and terminating in eastern Missouri, this pipeline was constructed principally to link the expanding natural gas production of Wyoming and western Colorado to midwestern markets, and to eventually extend to markets in the northeastern United States (in 2011).

At the close of 2008, EIA’s inventory of proposed pipeline projects9 reflects a potential addition of about 35.4 Bcf per day of natural gas pipeline capacity during 2009, about 19 percent less than in 2008. While the completion of all the currently anticipated projects on schedule or as designed is unlikely, 2009 will likely also be the second largest year for natural gas pipeline construction in this decade.

U.S. Imports and Exports: 2008

The net volume of U.S. natural gas imports decreased by 20.9 percent from 2007 to 2008, as both pipeline imports from Canada and LNG imports declined and U.S. exports increased. The United States in 2008 received net volumes of 2,996 Bcf, which were 789 Bcf less than 2007 levels (Figure 9). The decrease resulted largely from a 632-Bcf decline in gross imports, including declines of 419 Bcf in LNG supplies, 202 Bcf from Canada, and 11 Bcf from Mexico. In absolute terms, the net imports were the lowest since 1997.

Figure 9. Imports Represented a Smaller Share of Consumption than in Recent Years
Source: Energy Information Administration, based on data from the Office of Fossil Energy, U.S. Department of Energy.   Figure Data

The fall in imported natural gas to the United States reflects the increased need for natural gas in other countries willing to compete for available global supplies. The role of imports in meeting U.S. demand changed radically over the course of the last 20 years. Net imports of natural gas to the United States rose substantially since the mid-1980s, when pipeline imports from Canada began a dramatic increase. As expansion of imports from Canada fell off early this decade, additional imports of LNG flowed into the United States. However, this trend of increasing import volumes stalled at least temporarily as net imports only met about 13 percent of overall U.S. natural gas consumption in 2008, which is the lowest percentage since 1997.

Imports from Canada declined in 2008
Monthly gross imports from Canada in 2008 showed year-over-year increases at the beginning of the year. However, there were year-over-year declines in each month after April, thus gross imports for the entire year from Canada were 202 Bcf, or 5.3 percent, lower than in 2007. The trade balance between the United States and Canada was also increasingly affected by growing U.S. exports to Canada, which primarily occur through the Vector Pipeline near Detroit, Michigan. In 2008, the volume of U.S. exports to Canada increased 85 Bcf, or 18 percent, to 567 Bcf. Despite the resulting large decline of 8.7 percent in net imports from the country, Canada continued to be the source of the largest volumes of natural gas imported into the United States, being the source country for 90 percent of gross receipts of foreign natural gas in 2008. U.S. imports from Canada declined as the result of lower production in the country’s Western Canadian Sedimentary Basin (WCSB), which accounts for the vast majority of supply in Canada. WCSB field receipts declined 3.9 percent in 2008, which reduced the amount of natural gas available for export to the United States.10

Volumes of LNG and the Diversity of LNG Sources Down
In 2008, the United States imported the gaseous equivalent of 352 Bcf of LNG, which is about 54 percent lower than the annual total of 771 Bcf received in 2007, and the lowest annual volume since 2002. Although global liquefaction capacity has increased considerably since 2005 as the result of capacity additions in Egypt, Trinidad and Tobago, Nigeria, and other countries, maintenance delays and lack of available feedstock natural gas caused worldwide LNG production to grow at a much lower rate than expected. Simultaneously, there has been strong demand for LNG in countries other than the United States, such as Japan, Spain, France, Belgium, and the United Kingdom. LNG traders with options to deliver to multiple destinations found higher prices, and more attractive markets, in Europe and Asia compared with the United States.

Deliveries of LNG from Trinidad and Tobago account for the majority of LNG imports to the United States (Figure 10). The Atlantic LNG facility located in Port Fortin, Trinidad and Tobago, now has the capacity to produce nearly 700 Bcf per year. In recent years, several African countries, including Egypt, Equatorial Guinea, Nigeria, and Algeria, also have been suppliers of LNG to the United States. However, just two African countries supplied LNG to the United States in 2008 and their overall volumes were quite low: Egypt (55 Bcf) and Nigeria (12 Bcf). Norway, where the Snohvit LNG plant has recently began operating at near-full capacity, was the source country for 17 Bcf, while Qatar was the source country for a single cargo carrying the equivalent of 3 Bcf. For the first time in 20 years, the United States did not receive any cargos from Algeria.

Figure 10. The Majority of LNG Deliveries to the United States were Imported from Trinidad and Tobago
Source: Energy Information Administration, based on data from the Office of Fossil Energy, U.S. Department of Energy.   Figure Data

Despite the temporary decline in LNG imports during the year, industry continued with plans to expand infrastructure in the United States in anticipation of bringing competitively-priced LNG from a variety of countries. Two new onshore facilities in the Gulf of Mexico region and one facility in offshore Massachusetts became operational in 2008. On April 12, 2008, Sabine Pass LNG, L.P. took delivery of the LNG tanker the Celestine River at its new terminal located in Cameron Parish, Louisiana, and became the first new onshore LNG terminal to open in the United States in more than 25 years. On April 15, Freeport LNG L.P., which broke ground on its facility on Quintana Island, Texas in 2005, received the LNG tanker Excelsior. The Northeast Gateway port offshore Massachusetts received its first supplies May 23, but the less-than-1 Bcf delivered from Trinidad and Tobago was the only volume accepted at the port during the year. With these terminals now operational, U.S. capacity to receive LNG imports has increased from approximately 5.0 Bcf per day at the end of 2007 to about 9.1 Bcf per day as of the end of the year.

1 Energy Information Administration, Impact of the 2008 Hurricanes on the Natural Gas Industry, http://http://www.eia.gov/pub/oil_gas/natural_gas/feature_articles/2009/nghurricanes08/nghurricanes08.pdf
2 Henry Hub daily spot price data from Intelligence Press, NGI’s Daily Gas Price Index.
3 Price range is defined as the difference between the minimum and maximum prices for the year.
4 The Short-Term Energy Outlook is available at: http://www.eia.gov/emeu/steo/pub/contents.html
5Opal Hub spot price information provided by NGI’s Daily Gas Price Index.
6 For more information, see Lifting of the Moratorium on Offshore Drilling (2008), at: http://www.eia.gov/oiaf/aeo/
7 For more information, see the Annual Energy Outlook 2009, at: http://www.eia.gov/oiaf/aeo/
8 The estimate of peak working gas storage capacity is based on the maximum field-level reported vollumes of natural gas in storage, which often are less than the maximum working gas capacity for the field. U.S. Peak capacity as of mid 2008 was the equivalent of about 92 percent of design capacity for working gas. More information is available in the EIA report, Estimates of Peak Underground Working Gas Storage Capacity in the United States (October 2008), at: http://www.eia.gov/pub/oil_gas/natural_gas/feature_article/2008/ngpeakstorage/ngpeakstorage.pdf.
9 Source: Energy Information Administration, GasTran Natural Gas Transportation Information System, Natural Gas Pipeline Projects Database, 2008.
10 Canadian Natural Gas Markets: Western Canada Monthly Supply Update, FirstEnergy Capital (Calagery, Alberta, January 13,2009)