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Weekly Natural Gas Storage
Impact of Higher Natural Gas Prices on Local Distribution Companies and Residential Customers
Residential Natural Gas Prices: What Consumers Should Know
An Assessment of Prices of Natural Gas Futures Contracts As A Predictor of Realized Spot Prices at the Henry Hub
Overview of U.S. Legislation and Regulations Affecting Offshore Natural Gas and Oil Activity
Changes in U.S. Natural Gas Transportation Infrastructure in 2004
Natural Gas Residential Choice
Previous Issues of Natural Gas Weekly Update
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Overview:  Thursday, September 27, 2007 (next release 2:00 p.m. on October 4, 2007)

Since Wednesday, September 19, natural gas spot prices increased at most markets in the Lower 48 States outside the Rocky Mountain region.  Prices at the Henry Hub rose 24 cents per MMBtu, or 4 percent, since Wednesday, September 19, to $6.48 per MMBtu.  At the NYMEX, the futures contract for October delivery at the Henry Hub expired yesterday (September 26) at $6.423 per MMBtu, rising 24 cents or 4 percent since last Wednesday, September 19.  Natural gas in storage was 3,206 Bcf as of September 21, which is 8 percent above the 5-year average (2002-2006).  The spot price for West Texas Intermediate (WTI) crude oil fell $1.68 per barrel on the week (Wednesday-Wednesday) to $80.31 per barrel or $13.85 per MMBtu.





Natural gas spot prices increased at most market locations since last Wednesday, September 19.  Despite shut-ins totaling nearly 2.3 Bcf per day as of Friday, September 21, according to the Minerals Management Service (MMS), natural gas prices generally declined heading into the weekend, as moderating temperatures and soft weekend demand for natural gas likely accounted for the pattern of declining prices.  Nevertheless, a new warm front, returning industrial demand, and injection demand for natural gas likely accounted for the price recovery since Monday, September 24.  On a regional basis, cumulative price hikes outside the Rocky Mountain region averaged between 22 and 40 cents per MMBtu, or 3 and 6 percent, since last Wednesday, September 19.  The largest price increases since last Wednesday occurred principally in the Northeast region, where a return to warmer temperatures contributed to price increases averaging 39 cents per MMBtu.  In the markets along the Gulf of Mexico, price increases averaged between 30 and 40 cents per MMBtu. Tropical disturbances in the Gulf Mexico and shut-in natural gas production contributed to price hikes in the region, with the MMS reporting continuing shut-in natural gas production in the Gulf of Mexico of 0.20 Bcf per day as of Tuesday, September 25.  Prices in the Rocky Mountain region posted the smallest average increase on a regional basis, rising about 4 cents per MMBtu, with some individual markets in the region posting declines of as much as 35 cents per MMBtu.  Continuing transportation constraints in the Rocky Mountain region doubtlessly account for the unusual pricing patterns in the region. 





At the NYMEX, prices for the futures contracts for delivery in the next 12 months increased, with the 12-month futures strip (October 2007 through September 2008) rising about 15 cents per MMBtu, or about 2 percent, since last Wednesday, September 19. The futures contract for October delivery expired yesterday (September 26) at $6.423 per MMBtu, climbing 79 cents per MMBtu, or 14 percent, during its time as the next-month contract.  This is the highest expiry for a NYMEX natural gas futures contract since June 27, 2007, when the futures contract for July delivery at the Henry Hub expired at $6.929 per MMBtu.  The prices of the NYMEX futures contract for delivery at the Henry Hub during the months of the upcoming 2007-2008 heating season (November 2007 through March 2008) increased by 14 cents per MMBtu, or 2 percent, on average, since last Wednesday.  Overall, the 12-month futures strip (October 2007 through September 2008) traded at a premium of about $1.15 per MMBtu relative to the Henry Hub spot price, averaging $7.63 per MMBtu as of Wednesday, September 26.  


Recent Natural Gas Market Data



Working gas in storage totaled 3,206 Bcf as of Friday, September 21, which is 8 percent above the 5-year average inventory level for the report week, according to EIA’s Weekly Natural Gas Storage Report (see Storage Figure).  Stocks were 37 Bcf below the 3,243 Bcf in storage at this time last year, but exceeded the 5-year average by 238 Bcf.  On the week, net injections into working gas storage totaled 74 Bcf, matching the 5-year average injection and falling slightly below last year’s net injection of 79 Bcf for the same report week.  Temperatures in the Lower 48 States were moderate and somewhat cooler than normal (see Temperature Maps). These moderate temperatures would result in lower natural gas demand, thereby contributing to larger net injections of natural gas into storage.  However, shut-in natural gas production in the Gulf of Mexico reduced available current supplies, and so limited net injections during the report week. 





Other Market Trends:

EIA’s Weekly Natural Gas Storage Report (WNGSR) Becomes a Principal Economic Indicator:  With today’s release of the schedule of release dates for Principal Federal Economic Indicators for 2008, the Office of Management and Budget has indicated that the WNGSR will officially become a principal economic indicator in 2008.  Principal Federal economic indicators are the major statistical series that describe the current condition of the economy. They are compiled, released, and periodically evaluated in accordance with procedures established in OMB Statistical Policy Directive No. 3. The schedule for principal economic indicators is available at:


EIA to Introduce Changes to the Weekly Natural Gas Storage Report (WNGSR):  The Energy Information Administration (EIA) will transition to a new WNGSR on November 1, 2007.  The three areas of change are the design, release procedure, and new Web address.  All customers of the WNGSR are encouraged to review the sample Web site to familiarize themselves with the revised contents.  Additionally, EIA urges customers to participate in the release tests and provide feedback.  Additional details are available at  


FERC Proposes Revisions to Financial Reporting Requirements: With the aim of improving transportation-related information, the Federal Energy Regulatory Commission (FERC) on September 20 proposed several revisions to financial forms that are submitted by jurisdictional entities. The proposed rule would require natural gas companies to submit additional revenue information, such as income from shipper-supplied gas. Interstate pipeline companies would also have to identify the costs and revenues associated with affiliate transactions, as well as provide additional information on incremental facilities and discounted and negotiated rates. In releasing the proposed new reporting requirements, FERC noted a substantial decline in rate filings under Section 4 of the Natural Gas Act in recent years. As a result, the Commission and pipeline shippers increasingly must rely on the data contained in FERC’s financial and operational forms (filed by interstate pipeline companies) for an understanding of current trends and issues in the marketplace. The proposed reporting requirement would revise FERC Form. 2, “Annual Report for Major Natural Gas Companies,” FERC Form 2A, “Annual Report for Non-Major Natural Gas Companies,” and FERC Form 3-Q, “Quarterly Financial Report of Electric Utilities, Licensees and Natural Gas Companies.” With this additional information, shippers will be able to make more informed decisions on whether to file complaints under Section 5 of the Natural Gas Act (NGA) against pipelines (thereby requiring an adjustment to rates). Natural gas pipeline companies subject to the new requirements would have to file revised Form 3-Q quarterly reports beginning with the first quarter of 2009. The revised Forms 2 and 2-A for calendar year 2008 would have to be filed by April 30, 2009. In a related action, FERC also issued a Notice of Inquiry (NOI) seeking comment on several specific proposals for natural gas pipeline rate recovery of the costs for fuel use and lost and unaccounted-for gas. The NOI seeks comment on FERC’s policy regarding the method of cost recovery used by pipelines and whether that policy should change to prescribe a uniform recovery method for all pipelines.


Status Update on LNG Projects: A number of new projects to import liquefied natural gas (LNG) into the Lower 48 States will soon be online, according to project developers. In a recent presentation, Cheniere Energy, Inc., which is a part-owner of the Freeport LNG project in Brazoria County, Texas, said it expects construction of the terminal to be complete by early 2008. Freeport LNG, which will have a send-out capacity of 1.5 billion cubic feet (Bcf) per day, will be the first new onshore LNG terminal in the Lower 48 in over 2 decades. Cheniere is also the sole owner of the Sabine Pass LNG terminal in Cameron Parish, Louisiana, which is scheduled for opening in early 2008. A first cargo is expected to arrive at the terminal during the month of February 2008, as Cheniere Energy recently announced it already has chartered a vessel for this delivery. The terminal will have send-out capacity of 2.6 Bcf per day initially, with an expansion of send-out capacity expected later. A third onshore terminal, Sempra LNG’s Cameron LNG (also located in Cameron Parish, Louisiana), is expected to be online by the end of 2008, adding 1.8 Bcf per day of LNG import capacity to the region. Additionally, proposals for two ports to be located offshore Massachusetts are advancing and are planned for completion before the 2008-2009 winter. Construction of Excelerate Energy’s Northeast Gateway port (an offshore mooring terminal that accepts natural gas that has been regasified onboard LNG tankers) is well underway and may be complete by this winter, according to Excelerate Energy. Suez Energy, the owner of the Neptune LNG project (which similarly has no storage and is simply an offshore port receiving regasified LNG) expects to complete construction of its offshore Massachusetts project before the 2008-2009 winter. With these projects, U.S. LNG import capacity is expected to double to more than 10 Bcf per day by the end of 2008. In addition, more terminals are planned to be built in the future. The Federal Energy Regulatory Commission (FERC) last week approved Calhoun LNG’s plan to construct and operate an onshore LNG import terminal in Port Lavaca, Texas, with a send-out capacity of 1 Bcf per day. The company’s affiliate, Point Comfort Pipeline Company, also is authorized to construct and operate nearly 27.1 miles of new 36-inch-diameter pipeline to transport the 1 Bcf of gas per day from the Calhoun terminal to interstate markets. FERC also authorized Southern LNG to increase in two construction phases the storage capacity of the Elba Island LNG import terminal near Savannah, Georgia, by 8.44 Bcf and increase its vaporization capacity by 900 million cubic feet of gas per day.


Natural Gas Transportation Update:

  • Effective on September 24, Kern River Gas Transmission Company announced that the operational capacity at the Coyote Creek compressor station will be reduced to 1,875,000 decatherms (Dth) per day.  According to the company, the capacity reduction is the result of a change in the receipt and delivery nomination pattern of Kern River’s customers and will ensure that Kern River is able to physically receive and transport supplies that come into the system from receipt points located in Wyoming.  The only supplies unaffected by this change are at the Goshen station, which is located immediately upstream of the Elberta compressor station in Utah.


  • On September 26, Cheyenne Plains Gas Pipeline Company issued an update to the force majeure that was issued on September 16 as a result of damages to a significant amount of instrumentation and electrical wiring. The damages occurred when a fire ignited at the Cheyenne Plains compressor station, which is located inside the fence of El Paso’s Western Pipeline’s Cheyenne Station yard in northern Colorado.  The company is expecting to return to full service by the middle of November.  A definite date for return depends on factors such as weather or additional findings that may cause changes in the work plan.  The company will provide its shippers with weekly updates until the station returns to service.  The company announced that as of September 27, Cheyenne Plains will raise the operationally available capacity at Cheyenne Plains East from 435 to 455 MMcf per day.


  • Northwest Pipeline Corporation notified all shippers of a declared deficiency period at the Muddy Creek North compressor station, beginning September 25.  Northwest will be performing anomaly investigations between the Muddy Creek and the Kemmerer compressor stations in Wyoming.  Since primary firm nomination requests through the station have exceeded the available capacity of 652,000 Dth per day and the constraint point actual capacity of 577,000 Dth per day, the pipeline declared a deficiency period until the end of October.  Based on the design capacity of 652,000 Dth per day, the daily deficiency volume is 75,000 Dth per day.


  • Florida Gas Transmission Company (FGT) issued an Overage Alert Day for September 27 with a 25 percent tolerance level as a result of high temperatures in its service territory.  FGT announced that it would not interrupt previously scheduled market area interruptible transportation service below the elapsed-prorated-scheduled quantity. 



 Short-Term Energy Outlook