Friday, July 24, 2009

Rocky Mountain Natural Gas Lowest in USA

Natural Gas Outlook: Prices Rise, Storage Above 5-Year Average

Price increases at all market locations during the report week were likely a response to increased cooling demand as warm temperatures prevailed across the lower 48 States. With a mean temperature in the 80s during the report week, the price at Florida’s sole gas trading location rose 47 cents to $4.24 per MMBtu. The Florida Gas Transmission Citygate location is the only place in the country with a price above $4. Elsewhere, average regional price increases ranged from 11 cents in South Texas to 32 cents in the Rockies. Most average regional price increases were between 15 and 20 cents. However, warmer weather was not the only factor influencing prices in all regions. For example, Louisiana posted some of the most moderate price increases, despite average temperatures in the 80s in the Gulf Coast region. The average price in Louisiana increased 11 cents to $3.33 per MMBtu. Abundance of working gas in storage in the region tempered price increases.

Despite relatively large increases, prices in the Rocky Mountains are the lowest in the country. Rocky Mountain prices increased an average of 32 cents to $2.98 per MMBtu, despite mild weather in the region. The 8 of the 12 Rockies trading locations that closed below $3 per MMBtu on July 15 were the only places in the country to do so. In fact, all trading locations in the Rockies fell below $3 during the report week, as maintenance on the Rockies Express Pipeline caused some natural gas to be stranded. Prices bounced back at the end of the week as a result of warmer weather, however, with temperatures above 90 degrees in Salt Lake City, Utah. Additionally, Rockies prices have fallen from an average of $4.35 per MMBtu since the beginning of 2009, although the difference between the Rockies and Henry Hub prices has tightened as the pipeline infrastructure has improved.

Though price gains this week reversed losses from the previous week, prices in all trading locations are still relatively low. Year-to-date, prices at the Henry Hub have fallen 40 percent from $5.63 per MMBtu. The current Henry Hub price of $3.37 per MMBtu has declined 70 percent from the year-ago closing price of $11.15 per MMBtu. The WTI crude oil contract has similarly declined, falling 52 percent from the closing price of $129.43 per barrel 1 year ago. Price declines in the past year are likely the result of the declining economy, reduced demand, and robust inventories. Additionally, the Baker Hughes natural gas rotary rig count has fallen by 47 percent to 672 from levels of 1,267 at the beginning of the year. Changes in the rig count generally lag changes in price by at least several weeks. (See Other Market Trends).

Unlike spot prices, futures prices fell slightly at the New York Mercantile Exchange. The August 2009 contract fell to $3.283 per MMBtu, from $3.353 per MMBtu. The contract declined in price 4 out of the 6 trading days in the reference period. Overall, the losses during the week reversed mid-week gains, when the contract rose 6 cents on July 9 and 17 cents on July 14. During its tenure as the near month contract, the August 2009 contract has lost 66 cents, or nearly 17 percent of its value. Since the beginning of the year, the August contract has fallen 49 percent, from $6.400. The 12-month strip (the average of prices for the August 2009 through July 2010 contracts) fell from $4.850 to $4.755, a decline of almost 10 cents, or about 2 percent. Declines in individual contract prices ranged from 2.3 cents (October 2009) to 13 cents (March 2010). The futures prices likely reflect expectations of robust storage inventories in the coming months.


Working gas in storage increased to 2,886 Bcf as of Friday, July 10, 2009, according to EIA’s Weekly Natural Gas Storage Report (see Storage Figure). This year’s implied net injection of 90 Bcf exceeded the 5-year (2004-2008) average injection of 88 Bcf, but fell short of last year’s injection of 102 Bcf for the same week. Natural gas in storage is now 25.6 percent above inventories of 2,297 Bcf 1 year ago, and 18.7 percent above the 5-year average of 2,432 Bcf. Natural gas in storage is now at its highest level for any week in the month of July since collection of weekly storage data began in 1994. Levels for the Producing region and the West region are also at all-time highs for July. Regionally, this week the East region injected 62 Bcf, the West region injected 9 Bcf, and the Producing region injected 19 Bcf. For the end of the injection season, EIA’s Short-Term Energy Outlook is predicting inventories of 3,670 for the month of October.

The above-average storage injection partly resulted from slightly cooler-than-normal temperatures during the report week (see Temperature Maps and Data). The average temperature for the United States was 72.6 degrees during the report week, compared with 74.4 degrees for both the same week last year and the normal temperature. However, temperatures in the West South Central Census Division, which includes Texas, Louisiana, Arkansas, and Oklahoma, averaged 84.3 degrees, which was 2.1 degrees higher than the normal temperature and 3.6 degrees more than the previous year. This region was the only region with temperatures warmer than normal and warmer than last year.

Other Market Trends

EIA releases Country Analysis Brief on Canada. The Energy Information Administration (EIA) on July 9 issued a Country Analysis Brief describing the energy profile of Canada. Canada is the largest source of U.S. energy imports, with almost all of Canada’s exports going to the United States. According to the County Analysis Brief, Canada produced 6.6 trillion cubic feet (Tcf) of natural gas in 2007 and consumed 3.3 Tcf. As of January 2009, Canada had 57.9 Tcf of reserves. Canada’s natural gas production is concentrated in the Western Canada Sedimentary Basin (WCSB), particularly in Alberta. Many analysts predict that conventional natural gas production in the area has likely peaked, and future production will increasingly come from coalbed methane and shale in the WCSB. Natural gas located in Arctic areas will also likely play an increasingly important role in Canada’s natural gas production, as the Mackenzie Delta in the Northwest Territories holds between 5 and 6 Tcf of recoverable natural gas. The Mackenzie Valley pipeline, a 760-mile project planned for the area, would transport gas from the Arctic region to a connection with the existing transportation system in Northern Alberta. Canada is also looking to liquefied natural gas (LNG) gas to deal with possible future supply shortfalls in the future—several regasification terminals mostly in the east, as well as one liquefaction terminal in the west, have been proposed for Canada. The full index of Country Analysis Briefs can be found at

MMS Reports Results of Central Gulf of Mexico Sale 208. The Minerals Management Service (MMS) announced on July 10 that the Central Gulf of Mexico Oil and Gas Lease Sale 208 attracted a total of $690 million in high bids and awarded 328 leases to the successful high bidders. MMS received 476 bids from 70 companies, with the sum of all high bids received totaling $703 million. MMS evaluates each high bid to ensure the public receives fair market value before awarding a lease. MMS rejected high bids totaling nearly $13 million on 19 tracts as a result of their evaluation process. Shell Gulf of Mexico Inc. had the highest number of accepted high bids, 39, totaling almost $154 million. Shell also submitted the highest accepted bid of approximately $66 million.

Natural gas rotary rig count continues to decline. Baker Hughes Incorporated reported that the natural gas rotary rig count was 672 as of July 10, representing a 16-rig decline from the previous week. Rigs are at their lowest level since May 10, 2002. Natural gas rigs have fallen 58 percent from their highest-recorded level of 1,606, reached in late summer 2008. However, the decline appears to be flattening. Rigs recently posted an increase on June 19 and July 2. For the first 4 weeks of 2009, the average change in rigs was a decline of 40.5. For the previous 4 weeks (including the most recent data), the average change in rigs was a decline of 3.25. Additionally, horizontal rigs (both oil and natural gas) have outnumbered vertical rigs (also both oil and natural gas) for the eighth consecutive week. In March, the level of horizontal rigs overtook the number of vertical rigs for the first time since Baker Hughes began publishing data by drilling type. On July 10, horizontal rigs totaled 390 as of July 10, a decline of 6 from the previous week. Over the same period, the vertical rig count fell by 10 to 361.

Natural Gas Transportation Update

Texas Gas Transmission, LLC on July 10 revealed that it had found pipeline anomalies in the newly-constructed Fayetteville Lateral in Arkansas and Greenville Lateral in Mississippi. The pipeline company said that testing of pipe samples may require up to 2 months to complete. In the interim, pipeline operating capacities will be significantly reduced. Repairs of the laterals, which serve growing production from the Fayetteville Shale, will occur over several months after the results from testing are received. According to Texas Gas, pipeline work on various segments of the laterals could continue for up to 5 months. Although Texas Gas will attempt to maximize flows on its laterals during this time, shippers should anticipate capacity limitations. Texas gas will release details of its remediation schedule as they become available.

Sea Robin Pipeline Company, LLC on Tuesday, July 14, said it was beginning to repair damage to its pipeline in the western Gulf of Mexico. The repairs are part of the pipeline’s continuing efforts to restore infrastructure damaged last year during Hurricane Ike. Repairs to the south end of Sea Robin’s 30-inch diameter segment from East Cameron 334 to East Cameron 195 are expected to be complete this week, after which Sea Robin will initiate hydrotesting of the pipeline. Full operations of the pipeline are expected to commence by July 23.

Southern Natural Gas Company (SNG) on Wednesday, July 15, revealed that it will close a portion of its pipeline in the central Gulf of Mexico for up to 6 days. SNG’s West Delta 12 receipt point will be shut in as the pipeline abandons its 16-inch diameter Mississippi Canyon 268 Line. The closure will begin on July 19 or July 20, according to SNG. The pipeline also announced that it will begin about 3 weeks of maintenance on July 17 at the Mississippi Canyon 194 platform. This work will require the shut-in of two Mississippi Canyon meters and the Romere Pass meter.

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