The average monthly wellhead natural gas price fell from a record high of $10.35/Mcf in October 2005 to $5.03/Mcf in October 2006, which was the lowest monthly average since April 2004. But when one steps back a bit and looks at the market on an annual basis the 2006 roller coaster looks a bit smaller.

The average annual wellhead price for 2006 was $6.42/Mcf, down nearly a dollar from the 2005 average of $7.33/Mcf but about $1 above the 2004 average of $5.46/Mcf. The 2006 average annual spot price at the Henry Hub was 29% below the 2005 average. And while monthly average prices in all four consumer sectors — residential, commercial, industrial and power generation — fell from fall 2005 levels, the 2006 annual average price in the residential sector was 7% higher than the 2005 average.

Those are the numbers on top of the trends described in the Energy Information Administration’s (EIA) “Natural Gas Year-In-Review 2006,” a look back at all or most of last year (depending upon data availability) in anticipation of the agency’s “Natural Gas Annual 2006,” the official assessment, which is scheduled for a December release.

It’s no surprise that EIA found weather to be the main driver of the market. Last year was significantly warmer than normal, yielding a mild winter and relatively hot summer. Summer gas demand for power generation was noteworthy, particularly since it resulted in the first storage weekly net withdrawal during “injection season” on record during the week of July 21, 2006, EIA said (see Daily GPI, July 28, 2006). But then there was another injection season net withdrawal for the week ending Aug. 4, 2006 (see Daily GPI, Aug. 11, 2006).

Working gas levels began 2006 high and continued to exceed monthly inventories for each of the previous five years, contributing to the price softness seen through much of the year, EIA said. “However, prices likely influenced storage levels as well,” the agency said. “The spot price remained in contango with the New York Mercantile Exchange futures prices for delivery during the 2006-2007 heating season for almost every 2006 trading day.” That meant there was still money to be made from putting the gas back into the ground.

Storage at the end of the heating season, March 31, 2006, was 1,692 Bcf, the highest level for the date since 1991, EIA said. Contributing to this was the first-ever weekly net injection recorded during a withdrawal season, which was 1 Bcf for the week ending Dec. 29, 2005 (see Daily GPI, Jan. 6, 2006).


Despite the lingering effects of 2005 Hurricanes Katrina and Rita, the industry was able to grow production in 2006, thanks mainly to the Rockies, Midcontinent and prolific producing basins in North and East Texas. Total marketed production in 2006 increased by about 2% over the prior year to 19.34 Tcf, despite significant declines in the offshore Gulf of Mexico, EIA said.

As of October 2006, federal offshore Gulf of Mexico production in 2006 was 2.37 Tcf, which is a decrease of 13% from the corresponding period in 2005. The region accounted for only 15% of cumulative domestic marketed production in the January-October 2006 period, when historically it has provided 20% of annual domestic marketed production.

The offshore Gulf is now widely known as a gas production problem child. While the number of gas-directed drilling rigs has significantly increased in recent years, that’s not true in the Gulf. In late December 2006, there were 81 gas-directed rigs in the Gulf, which is well below the record of 134 engaged in gas drilling during July and August 2000, EIA said.

Onshore, the largest production growth occurred mainly in the top producing states: Texas, Oklahoma and Wyoming. Production from the three states represents nearly 73% of the production increase seen last year, EIA said. “The largest producing state, Texas, increased onshore production by 259 Bcf, or about 5%, in the first 10 months of 2006, which accounts for about 46% of the overall increase,” EIA said. Credit the Fort Worth Basin’s Barnett Shale and, in particular, drilling and completion technology advances in the booming play.

Last year there was an average of 133 rigs drilling for oil and gas in Texas District 5, where the Barnett Shale lies. This is 53 more rigs than the average in 2005, and the increase represents 20% of the yearly increase in total average U.S. rigs, EIA said. Oklahoma and Wyoming saw production increase of about 5% each, EIA noted.


It’s a good thing domestic onshore basins were able to step up last year as both pipeline and liquefied natural gas (LNG) imports were a disappointment with imports declining 5% from 2005 to 2006 overall. The United States received 179 Bcf less imported gas than it got in 2005. Gross imports declined 154 Bcf, including a 103 Bcf drop in gas imported from Canada. Gross imports from Mexico saw a 3 Bcf decline, and LNG imports declined 48 Bcf. Canada continued to be the source for the largest volumes of gas imported, accounting for 86% of gross receipts of foreign gas.

LNG imports declined for the second year in a row. “In 2006, the United States imported the equivalent of 584 Bcf, which is about 8% lower than the 631 Bcf received in 2005 and 10% lower than peak receipts of 652 Bcf in 2004,” EIA said. Imports came from Trinidad and Tobago, Egypt, Nigeria and Algeria, but not from countries in the Middle East and the Pacific Basin as they have in the past. “LNG traders with options to deliver to multiple destinations found higher prices, and more attractive markets, in Europe and Asia compared to the United States,” EIA said.

Fewer LNG cargoes left the four onshore regasification terminals significantly underutilized. The Trunkline LNG facility in Lake Charles, LA, had the lowest utilization rate, EIA said, at an average of about 25% during the year. The terminals in Everett, MA, Elba Island, GA and Cove Point, MD had utilization rates of about 66%, 33% and 32%, respectively. The Gulf Gateway offshore receipt terminal in the Gulf of Mexico only saw one cargo last year, EIA said.


It’s safe to say that whenever more LNG cargoes show up at U.S. shores there will be regasification capacity to meet them. Currently the industry seems more excited about building new pipelines to move gas out of the prolific Rocky Mountain and East Texas producing regions.

“The addition of 12.3 Bcf/d of new natural gas pipeline capacity in the United States in 2006 was 50% greater than the 8.2 Bcf/d which occurred in 2005,” EIA said. “Moreover, the addition of new pipeline mileage grew by 44% in 2006.”

Most of the activity was in Colorado, Wyoming and northeast Texas. Twenty-one of the 45 pipeline projects completed during the year were located in either the Rockies or East Texas regions. Rockies projects accounted for 26% of all new capacity installed during the year, and northeast Texas projects constituted another 25%.

Despite production declines, the Gulf of Mexico saw three medium-to-large capacity deepwater projects representing 2.4 Bcf/d of new capacity and 192 miles of pipe. The largest project was the 1 Bcf/d, 140-mile Independence Trail system.


Residential, commercial and industrial demand for gas all declined last year with the residential sector consuming more than 9% less than in 2005. The commercial sector used 6% less gas and the industrial sector used 2% less. “The electric power sector, however, offset much of the decline by consuming over 6% more natural gas than in the previous year,” EIA said. “Since 2003, electric power consumption [of natural gas] has increased by 22%, highlighting the growing contribution of this sector to natural gas demand.”

In 2005, the U.S. added 12,577 MW of gas-fired summer generating capacity and added another 7,822 MW during the first 11 months of 2006.

And power generators paid less for the gas they burned last year. Since fall 2005 the average monthly price for gas paid by power generators decreased from a record $11.85/Mcf in October 2005 to $5.75/Mcf in October 2006.

Declines in the residential and commercial sectors were blamed in part on warmer-than-normal weather but also on prices. “Although the residential price has decreased since the September 2005 record high of $16.60/Mcf, the average annual 2006 price increased to $13.76/Mcf, 7% higher than the previous record high set in 2005,” EIA said.

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