New carbon-emission regulations, current and future pipeline capacities, and the new Securities and Exchange Commission (SEC) rules will affect future valuations of oil and gas assets. This according to a panel at the recent Oil and Gas Investor and A&D Watch’s A&D Strategies and Opportunities conference in Dallas.

Carbon-emissions legislation could change asset values as early as 2010, said panelist Britton Richardson, partner with Atlanta-based Alston & Bird LLP. Industry experts, looking at possible new legislation, have considered using captured CO2 for use in enhanced oil recovery (EOR) as a viable option.

Although the technology sounds good, a multitude of issues must be resolved before implementation, said Richardson. Any attempt at storing CO2 must include provisions to reduce or eliminate possible leakage from facilities before injection into a reservoir for enhanced recovery.

Also, CO2 sourced from industry is highly regulated. “We think that once you take CO2 from an industrial source, you are subject to the Clean Air Act,” said Richardson. “You will have the Environmental Protection Agency camped in your backyard.”

Any producer using industrial CO2 will be responsible for managing records, tests and documents for EPA reports, increasing field-development costs, he said.

“Once you take CO2 from a regulated source, the CO2 is subject to federal regulations. Under the Waxman-Markey bill, the injector will be subject to federal statutes. The CO2 from industrial sources is rarely pure, so it is considered a hazardous substance. The legal exposure will outstrip benefits.”

“When CO2 is used for EOR, the EPA allowances are discounted, and that will wreak havoc on your evaluations,” said Richardson. “Any day now, the EPA will rule that CO2 is a danger to public health and welfare. The auto industry will have tailpipe-emissions regulations first. There are no incentives under the Clean Air Act to capture and store CO2.”

Take-away capacity is another important factor to consider in A&D activities, said panelist Tom Sherman, senior energy analyst for Denver-based Bentek Energy LLC.

Sellers and buyers should keep an eye on local and interstate pipeline capacities because a constrained area limits profitability as producers compete for space.

In a break from the past, Rocky Mountain gas production is finally “favored with plenty of take-away capacity” and another 2 billion cubic feet is planned in the next few years, said Sherman. As a result, the forward curve for gas prices from the Rockies has increased.

“The Rockies could be a big winner now, with the Ruby Pipeline and Kern River Pipeline expansions. That ensures gas can go to the Northwest, and westward to California,” he said.

Meanwhile, the U.S. can move about 12.6 billion cubic feet of gas out of the southeast Gulf of Mexico region.

Elsewhere, flows of gas into the Ohio Valley are increasing, he noted. “The Transco system is full all the time, so we are bumping up against capacity there.”

Companies plan as many as five expansions of Appalachian pipeline projects, which could move as much as 2.5 billion cubic feet per day of Marcellus shale gas to market. Increased Marcellus production will squeeze Rockies gas out of the Northeast.

One bright spot for the A&D market is the long-awaited new SEC rules, effective January 1, that “seem to have more liberal definitions of reserves,” said Scott Rees, chairman and chief executive of Dallas-based Netherland, Sewell & Associates Inc. For more on this, see “At Closing” in this issue.