Natural Gas Outlook: Demand Higher On Cold Weather, Spot Prices Down

 Resize text         Printer-friendly version of this article Printer-friendly version of this article

Prices
With cold temperatures gripping much of the country for the first half of December, the heating season is well underway with large storage withdrawals. Nonetheless, a trend of rising prices since Thanksgiving ended during this report week for most regions of the country. Following two weeks of increases, the price at the Henry Hub declined $0.24 per MMBtu to $4.22 and is now just one cent higher than its price at the beginning of December. During the report week, price changes at specific market locations depended largely on local weather conditions and constraints in transportation into local markets. While prices in the Gulf of Mexico region generally decreased in the range of $0.25-$0.30 per MMBtu, prices at several markets in the Northeast increased dramatically. In the Rockies and California, where weather conditions improved late in the report week, price decreases ranged from $0.05-$0.21 per MMBtu. The decline in prices this week, which appears counterintuitive and is a reversal of historically rising prices with extreme weather early in the season, in part reflects strength in current supplies. According to BENTEK Energy, LLC, U.S. production during the report week, which averaged close to 63 Bcf per day, was nearly 10 percent higher than the comparable period last year. At the same time, imports from Canada have also increased recently and natural gas in storage is near its historical high for this time of year (see Storage below). Because of the strength in current supplies, prices are far below their levels this time last year. On December 15, 2009, the Henry Hub price was $5.53 per MMBtu, or about 31 percent above yesterday’s average of $4.22.

Nonetheless, the extreme temperatures in many parts of the country led to large consumption increases during the report week. Compared with the prior week, U.S. natural gas consumption increased about 4.3 percent to an average of 96 Bcf per day. Combined consumption in the residential and commercial sectors also increased 4.3 percent, and exceeded 50 Bcf for most of the days of the report week. In the electric power sector, increased demand for electricity for heating purposes, primarily in the Southeast, contributed to a 6.5-percent increase in natural gas consumption relative to the prior week. Overall, U.S. consumption was 6.6 percent higher than the comparable period in 2009, according to BENTEK.

In the Northeast, prices rose significantly at certain markets as temperatures dipped as much as 20 degrees below normal. This week’s cold front contributed to the highest spot natural gas settlement prices at Northeastern trading points along the Atlantic seaboard since January 2008. The spot natural gas price at the Transco Zone 6 trading point in New York City peaked during the report week at $20.43 per MMBtu for delivery on Tuesday, December 14. On the week, the price at Transco increased $2.13 per MMBtu, following a sharp decrease yesterday. In the western portions of the Northeast, prices generally declined on the week, and the sharp prices seen in New York and elsewhere did not occur. The spot price at Dominion South in western Pennsylvania settled at $4.88 per MMBtu yesterday, lower on the week by $0.18. The stark difference in intraregional prices resulted from pipeline constraints between west and east portions of the region. Estimated natural gas flows into the entire Northeast market on Tuesday topped 31 Bcf per day, or 55 percent greater than normal. This estimated Northeast gas consumption was the highest recorded for any December day since BENTEK began collecting this information starting in 2005. Short-duration price spikes in the winter have been fairly common in New York City and New England. However, almost 4 Bcf per day of new pipeline projects for the region are targeted to enter service before November 2011, in large part to move more gas from the new shale wells in the Marcellus play to downstream markets.

In the West, natural gas spot prices decreased as extreme cold subsided. Despite increased flows on pipelines that transport supplies to the east, such as Cheyenne Plains Gas Pipeline, prices in the Rockies decreased at all trading locations. For example, the price for supplies on the Questar Corporation system in Utah decreased $0.12 per MMBtu to $4.04. Prices declined moderately in the Northwest. At Sumas, Washington, the price decreased by $0.05 per MMBtu to $4.25 in trading since the prior report week.

U.S. imports were significantly higher during the report week in comparison with the prior week, resulting in part from increased withdrawals from storage in Canada to meet heating demand in the United States. U.S pipeline imports from Canada during the report week increased 5.2 percent relative to the prior week to about 8.6 Bcf per day. Liquefied natural gas (LNG) imports (as measured by sendout from regasification terminals) also increased to an average of 1.2 Bcf per day, or 13 percent more than the prior week. While Canadian imports were about 14 percent higher than last year at this time, LNG supplies were still almost 21 percent lower than last year during the comparable week.



At the NYMEX, the price of the near-month contract for January delivery decreased $0.38, or 8.3 percent, during the report week to $4.22 per MMBtu. The decrease occurred likely in response to expectations of a reprieve from the extreme cold in consuming regions of the country, thus decreasing space-heating demand. While the early cold will likely result in large withdrawals from storage, the current strength in supplies may prevent any change in the pricing environmentfundamental. The January 2011 contract is trading much lower than the settlement prices of contracts for comparable months over the last 2 years. The January 2010 and January 2009 contracts expired at $5.81 per MMBtu and $6.14 per MMBtu, respectively.

Storage
Working natural gas in storage fell to 3,561 Bcf as of Friday, December 10, according to EIA’s WNGSR (see Storage Figure). The net draw of 164 Bcf is larger than the 5-year average draw of 153 Bcf but less than last year’s draw of 186 Bcf for the report week. The Producing region storage levels are now 73 Bcf above last year’s level, while the East region is 90 Bcf below. Working gas stocks in the West region are 18 Bcf below last year.

The week’s draw was significantly less than last year despite lower temperatures and higher heating degree days this year. The difference is likely largely due to a large increase in domestic natural gas production, which has lessened the need to draw gas from storage. According to the Short-Term Energy Outlook, December 2009 marketed production was just 59.5 Bcf per day, compared to a projected value of 63.1 Bcf per day for December 2010.

Temperatures were colder than normal in the lower 48 States during the week ending December 9. The National Weather Service’s degree-day data show that the temperature in the lower 48 States last week averaged 34.0 degrees, 5.3 degrees below normal, and 1.6 degrees below last year (See Temperature Maps and Data). Every region except the Mountain and Pacific averaged colder temperatures than normal. The South Atlantic region had the coldest temperature relative to normal at 33.9 degrees, 12.1 degrees less than normal. Heating degree days in this region were 53.4 percent above normal compared to an increase of 19.2 percent for the lower 48 States as a whole.

Other Market Trends
EIA Projects Growth in Natural Gas Production Through 2035. Expanding domestic shale gas resources are expected to lead to increased domestic natural gas production at lower prices, according to EIA’s Early Release of the 2011 Annual Energy Outlook (AEO). According to the report, which was published on December 15, the technically recoverable unproved shale gas resource is 827 trillion cubic feet (Tcf), which is 474 Tcf larger than estimated in last year’s AEO. Growth in natural gas extracted from shale formations will drive an increase in domestic natural gas production from 21.50 Tcf in 2009 to 26.78 Tcf in 2035. Production from shale is expected to grow to 12 Tcf in 2035, more than offsetting a decline in conventional production. Natural gas prices at the Henry Hub are expected to increase from the 2009 level of $3.95 per MMBtu to an average of $7.19 per MMBtu in 2035. Natural gas and renewable power plants will comprise the majority of generation capacity additions, according to the AEO. The share of generation from natural gas increases from 23 percent in 2009 to 25 percent in 2035. The AEO includes projections through 2035 and is based on a reference case assuming the use of technology that is current or reasonably expected to become available over the next decade. Additionally, the reference case does not include the effects of possible future policies. More information is available here: http://www.eia.doe.gov/oiaf/aeo/index.html. The full AEO will be released in March 2011.

Regulations Proposed for Drilling the Delaware River Basin. The Delaware River Basin Commission (DRBC) released draft natural gas development regulations that would conditionally allow natural gas development projects in the Basin areas of the Marcellus Shale. The proposed rules would allow water within the basin to be used for gas development if the water is “within the physical boundaries” of a DRBC-approved natural gas development plan. Under “specified conditions,” producers would be able to reuse treated wastewater, non-contact cooling water, recovered flowback and production water, and mine drainage waters for natural gas development. Additionally, the regulations call for a streamlining of the permitting process for gas development projects “that demonstrate that they satisfy certain criteria”—this would shorten the current 6- to 9-month lag time to less than 30 days. Three public hearings will be scheduled during the 90-day comment period to receive oral testimony on the proposed rulemaking.

Natural Gas Transportation Update
- Higher demand from cold weather this week prompted some pipelines to release alerts regarding their operations. On December 15, Florida Gas Transmission Company, LLC (FGT), issued an Overage Alert Day for customers in FGT’s market, with a 15% tolerance on negative daily imbalances. Mississippi River Transmission issued a System Protection Warning on December 15 and December 16 until further notice, due to cold weather in its market area. Due to “significantly lower than normal system weighted temperatures,” Northern Natural Gas issued a System Overrun Limitation in all market-area zones December 11 through December 15. Southern Natural Gas issued a Type 6 Operational Flow Order, effective December 12 through December 15, due to cold weather.

- Texas Eastern Transmission, LP, experienced an outage at its Bernville, Pennsylvania, compressor station on December 13, which was repaired and operational the following gas day. However, their Entriken compressor station remains offline, with an approximate capacity reduction of 65,000 dekatherms through and downstream on Entriken. Texas Eastern is continuing to investigate repair options for that compressor.

Source: U.S. Energy Information Administration



Comments (0) Leave a comment 

Name
e-Mail (required)
Location

Comment:

characters left


WinPig.Net

WinPig.Net is the newest management system from AgroSoft. This new program retains the user-friendliness of its predecessor while adding ... Read More

View all Products in this segment

View All Buyers Guides

Feedback Form
Generate Leads