Natural gas producers, especially those active in shale basins, could be in for a rough ride in 2009 and beyond if the current turmoil in the financial markets and the downturn in commodity prices continue unabated, producers told FERC Friday. And while industrial customers see lower gas prices as good news, they say now is not the time to relax.

“[The] lack of credit combined with a rapid decline in oil and gas prices in the last four months will likely result in significantly fewer shale wells being drilled. How deep the cuts go and the resulting impact on domestic production will probably not be known for some time. But if the current situation persists beyond next year, we can [expect] material production declines to continue for the next few years,” said Terrence Ruder, senior vice president of marketing and midstream division for Devon Energy Corp.

This contrasts sharply with the past three years during which gas-focused producers reinvested almost 130% of their cash flow into their drilling programs, increasing natural gas supply from 50 Bcf/d in 2005 to more than 56 Bcf/d this year, with shale gas accounting for a significant part of the growth, he said during the Federal Energy Regulatory Commission’s “State of the Natural Gas Infrastructure” conference in Washington, DC.

David Clay Bretches, vice president of marketing and minerals for Anadarko Petroleum Corp., agreed that rig activity will drop next year. “In 2009, we will see that number fall off substantially” due to the financial crisis and deep slide in gas prices. He believes wells with short-term commitments will be most affected. And because shale is a higher-priced gas, he said a falloff will occur there too.

Producers agreed that access was a major problem as well. “Access to land will continue to be a potential restriction to the growth of shale resources. In parts of the country where there are not established rules and responsibilities for local, state and federal agencies, especially for permitting and water access, it will be difficult to duplicate the pace of growth experience in the Barnett [Shale]” in Texas, Ruder said.

“Price risks can be mitigated by hedging…However, we cannot mitigate the risks stemming from regulatory uncertainty. One of the biggest regulatory hurdles blocking our ability to bring production on-line is related to permitting, particularly in the Rockies,” Bretches said. He noted that it often takes a producer 400 days to get a permit to drill in the Rocky Mountains. The end result for consumers is “fluctuations in supply availability and significant volatility in commodity prices.”

And an increased tax burden on producers could deter shale development, they said. “Any new taxes imposed on industry, such as the windfall profit tax now being discussed in Congress, will directly and immediately reduce investment in U.S. shale development and…affect production,” Ruder said, adding that repeal of existing tax incentives would take a toll on producers.

But if the financial, permitting and tax stars are aligned in favor of producers, Ruder estimated that U.S. shale development could triple to 15-20 Bcf/d, or one-fourth of expected U.S. demand, by 2018. Current shale development in the U.S. is approximately 6-8 Bcf/d, he said, adding that shale can be economically developed with a New York Mercantile Exchange pricing band of $6-9/MMBtu. The industry estimated shale reserve base ranges from 250 Tcf to 750 Tcf.

Ruder projects that the industry will need to spend more than $150 billion on drilling and completion costs to fully develop the Barnett Shale in the coming decades. Devon alone has invested $1.6 billion in gathering and processing systems in the Barnett since 2002, along with entering into contracts for up to another $2.3 billion to secure and use gas pipeline takeaway capacity.

Devon’s resource base in the Barnett has increased fivefold from 3.9 Tcf in 2002 to more than 18.3 Tcf now, Ruder said. Although some producers this year reported that Barnett gas production is in decline, Devon estimates the shale still has a potential of 50 Bcf to 200 Bcf per square mile. Devon first entered the Barnett with the acquisition of Mitchell Energy & Development Corp. (see Daily GPI, Aug. 15, 2001). Six years ago Devon was seeing a recovery rate of only 10-15% in the Barnett. But that has climbed to 30% or more due to the use of hydraulic fracturing simulation and other technology, he noted.

Zachariah Allen, president of Pan EurAsian Enterprises Inc., said there is a perception of a glut in the international liquefied natural gas (LNG) markets. “There was a certain amount of panic over-buying in the market, which has led now to an oversupply situation, along with a recession that’s caused prices to drop rather dramatically. The price of LNG is closely linked to oil prices,” he said. This is a far cry from last winter when LNG was close to $25/MMBtu on the Asian spot market.

Some believe that because of the apparent glut of LNG and receding prices that the United States could be in for a flood of imports next year, he said. Will this happen? he asked. “It all depends on how much…demand destruction there is in the rest of the word, particularly the Asian markets. It could well happen…in late spring, early summer,” Allen noted. U.S. consumption of LNG this year is down 55% from 2007.

“There’s no question that LNG will grow, but it’s going to be a rough path.” For now, “LNG finds itself as a swing supplier…a swing fuel,” Allen said. He believes development of some type of trading exchange for LNG is “inevitable.” This would be a “positive development to pin down those prices.”

Claire Burum, senior vice president of regulatory affairs for NiSource Gas Transmission and Storage, gave FERC high marks for processing applications for pipeline and storage facilities in a “timely manner,” and expressed support for letting the market decide which projects ultimately get constructed. The “firm contracts are the market’s vote,” she said.

FERC Chairman Joseph Kelliher agreed that the market — rather than FERC or regional officials — should be in charge of which projects get built. If FERC were in charge of planning the pipeline network, he said he doubted that the agency would have identified the need for the West-to-East Rockies Express Pipeline, the last leg of which is being constructed.

The Alaska natural gas pipeline almost went unmentioned at the conference until Commissioner Philip Moeller raised the topic. As long as gas supply is abundant in the Lower 48 states, “I don’t know if we’ll ever see the Alaska pipeline,” said Anadarko’s Bretches.

“I think it’s inevitable” because there’s too much gas in Alaska and too much gas in Russia, which could be transported via the Bering Strait to the U.S., Pan EurAsian’s Allen countered.

Although gas prices are considerably lower, industrial customers say this is no time to relax. “We’re happy that prices have moderated, but we view that as a time not to relax on any measure. It’s a respite; it’s good news for industrials. We’ve been given…a temporary reprieve,” said Alexander Strawn, chairman of the Process Gas Consumers Group.

“It takes energy, particularly natural gas, to run the economy,” and the nation needs new infrastructure to bring shale gas to market, he said. “We encourage FERC to be the voice of reason” and explain to lawmakers how environmental initiatives will affect energy development.

“We want the United States to proceed responsibly” with respect to global warming, Strawn said. But “we also [are] eager to have the debate resolved” to provide some certainty to industry.

Between now and 2030 Revis James of the Electric Power Research Institute said natural gas will continue to be a “principal factor” in the generation of electricity. By 2030 he estimates that gas consumption for power production could be 50-100% more than it was in 2007.

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