Concerns about the impact of methods used to extract gas from shale deposits could lead to tough restrictions—and crimp output for some producers
After years of talk about improved energy security for the U.S.—and a smaller carbon footprint for U.S. industry—natural gas seized the spotlight on Dec. 14 after ExxonMobil (XOM) announced a deal to acquire XTO Energy (XTO), one of the largest independent natural gas producers. The all-stock deal is worth $31 billion, plus the assumption of $10 billion in debt. But could environmental concerns about the methods used to extract gas from its hiding place in the depths of shale deposits spoil the party? There's been concern about a prolonged slump in natural gas prices below $4 per 1,000 cu. ft. (Mcf), due mostly to a supply glut from a production surge in unconventional gas deposits and a drop in demand due to the recession. But prices have briefly edged above the $5 level three times in the past three months, giving hope that demand is improving with the return of economic growth. The spot price of natural gas at Henry Hub, La., peaked above $13 in mid-June 2008 as all energy prices were spiking. Although natural gas is certainly one of the cleaner fuels, compared with coal or crude oil, there are other concerns when it comes to its environmental impact, both real and alleged. Most of those revolve around the use of water when drilling in unconventional gas reservoirs such as the Marcellus Shale that snakes through the Appalachian Mountains. There have been serious cases of water contamination near drilling sites in seven states, but so far there's no conclusive proof the cause is the fluids used in hydraulic fracturing, the drilling process used to release gas trapped in compressed rock formations such as the Marcellus Shale. Resistance to Fracturing
While 99% of the fluids' content is water and sand, the remainder is composed of up to 300 assorted chemicals that make drilling easier, either by reducing friction as the drill bit bores into rock or by keeping the spaces in the rock created by small explosions open after drilling. Oilfield service providers such as Halliburton (HAL), Schlumberger (SLB), and BJ Services (BJS), which control most of the $16 billion hydraulic fracturing market, aren't required to disclose the chemical content of the fluids they use. Environmental groups say some of the chemicals used in those fluids could be toxic in large enough concentrations. Although a link between the fluids and contaminated water supplies has yet to be proved, in New York State there has been a moratorium on new gas drilling permits since July 2008. A coalition of upstate conservation groups, including the local chapter of the Sierra Club, requested the drilling ban at least until a comprehensive environmental impact statement from the state Environmental Conservation Dept. has been completed and reviewed publicly. Some analysts and industry insiders think the resistance to hydraulic fracturing stems more from a not-in-my-backyard mindset among local residents and politicians than from any hard evidence linking water contamination to drilling fluids. Development of the Marcellus Shale has moved into parts of Pennsylvania and New York State that historically haven't experienced much drilling, says Scott Stevens, president of Upstream Energy Advisors, an oil and gas consulting firm, and a specialist in unconventional oil and gas resources.
"I'd rather have a well [in my neighborhood] than a strip mall, which is never going away," he says. "Within two months, the [drilling] rigs are gone. There may be a little gravel road leading to the wellhead, and there's one of those every 80 acres or so, so it's fairly invisible." Preventive Options
Clay Hoes, a sub-adviser for the $50 million AmEx Global Equities Energy Fund, hasn't backed away from companies that focus primarily on unconventional gas plays, which account for half of his 30% portfolio weight in exploration and production (E&P) companies. He also has a 22% exposure to oilfield service stocks. He believes producers moving into these resources will try to do whatever is needed to avoid contaminating local water supplies. Among their options are setting well casings earlier to prevent leaks and injecting pure water without chemicals, or even just air, into well holes, followed by sand to keep the fractures from closing again. Potential contamination from drilling is probably a less pressing concern for investors than bigger water issues, such as where to access the 3 million gallons of water needed to hydraulically fracture each well and how to best dispose of the roughly 1 million gallons of water that eventually return to the well's surface, say some industry pros. It's very hard to prove a connection between some of the chemicals used in hydraulic fracturing fluids and cases of groundwater contamination, says Brad Handler, an oilfield services analyst at Credit Suisse (CS) Equity Research. Rather than suggesting a structurally unsafe practice, he believes any contamination from hydraulic fracturing has thus far related to improper handling of fluids at the surface during disposal or inadequate casing of wells during construction. Producer Costs
A study by IHS Global Insight (IHS) about procedures related to compliance with the underground injection control requirement, published June 9, 2009, calculated additional costs of $109,833 per well for non-shale deposits and $47,333 for shale plays. The study projected a 20.5% reduction in the number of new wells drilled and a 10% loss of natural gas production over the next five years due to the added costs. "A lot of the additional costs had to do with monitoring of the frac jobs themselves," using seismic mapping and other techniques that tell you where the fracturing fluid is going within the rock formation, says Handler. "Part of the compliance measure would be mandating that a certain proportion of wells would have these fracture mapping and monitoring techniques, which are commercially available today, so you could say the fluid only [traveled] X feet, not 7,000 feet" through the rock formation. There would also be some cost associated with subjecting oilfield activities to the same permitting requirements as construction companies for sediments in runoff water under the Clean Water Act, says Handler. Regulation Outlook
The Independent Petroleum Association of America (IPAA) has estimated a cost of $100,000 per well for compliance with proposed federal regulation of fracturing. That's roughly a 5% increase for an average nonconventional well, says Dennis Fagerstone, an independent oil and gas consultant and former head of international operations at Pioneer Natural Resources (PXD).
Regulation of hydraulic fracturing has been assigned to the states since the definition of "underground injection control" (UIC) in the Safe Drinking Water Act of 1974 was revised under the Energy Policy Act of 2005 to exclude hydraulic fracturing. A congressional bill introduced on June 9, 2009, seeks to eliminate the exclusion under the SDWA. That would require fracturing companies to disclose the chemical content of fracturing fluids, which now are kept secret to protect proprietary formulas. If hydraulic fracturing does end up being subject to tougher regulations, any additional costs related to compliance won't necessarily be onerous for producers, says Handler at Credit Suisse. If regulation is limited to procedures around well sites, the impact may be relatively small, while moving up toward full UIC compliance would add potential expense, he wrote in an e-mail to Bloomberg BusinessWeek. The larger integrated companies like ExxonMobil that are looking to acquire unconventional gas resources are generally thought to have more comprehensive safety procedures in place anyway, compared with smaller companies, he says. The cost of restricting the chemicals that can be used, measured either in cost per well or possibly lower gas production, is harder to quantify, he added. Socially Responsible Perspective
Socially responsible investors, who try to minimize, if not eliminate, their exposure to companies and sectors with questionable environmental, labor, or corporate governance practices, also are keeping careful watch on developments in the natural gas industry. Reynders, McVeigh Capital Management, though positive about natural gas moving into the energy spotlight, hasn't been keen to invest in companies that use fracturing because of concerns about waste products generated by the technology and sensitivity about water issues, says Chat Reynders, a principal at the Boston-based firm. That's why he prefers EnCana (ECA) over XTO and was thrilled when the Canadian producer spun off its oil sands production unit Cenovus Energy (CVE), which was getting too aggressive in energy-intensive oil sands for his taste, at the end of November. "We liked that EnCana became more of a pure-play natural gas producer" and used the proceeds from selling the firm's Cenovus holdings to increase its exposure to EnCana and invest in Calgon Carbon (CCC), a water purification company. "We didn't invest in XTO because of how 'frac-ing' intensive it was," he says. "[EnCana has] enormous reserves not based on frac-ing. For us, that's the kind of natural gas company we want to invest in." Reynders sees the Exxon-XTO deal as the beginning of a trend in which more major integrated energy producers will acquire independent E&P companies in order to exploit their valuable shale deposits. Technological Promise
He expects responsible natural gas producers over time to increase their monitoring and use of technologies designed to protect the environment surrounding drilling sites, including water treatment processes. But he sees smaller, independent producers, which often are more vested in the local communities where they operate, as more likely to do so than the larger integrated players whose focus as they acquire these resources will be on exploiting them. But gas consultants Stevens and Fagerstone believe the major producers are more sensitive to damage to their public images and brand names if an environmental glitch occurs. The majors also can better afford to spend more money on such technologies, says Stevens. Just as advances in technology have enabled natural gas production to jump to more than 8 billion cu. ft. per day, from 2 billion, in the past five years, further technological breakthroughs may yet reduce the chances of environmental damage from drilling. Instead of trucking wastewater away to disposal wells buried thousands of feet underground, some unconventional gas producers are starting to use water treatment procedures such as reverse osmosis and electrodialysis to remove contaminants from the one-third of the water that typically returns to the wellhead after drilling. Treated water can either be reused in fracturing other wells or even for non-industrial consumption, says Stevens. EOG Resources (EOG) is currently filtering water that returns to the surface in its Marcellus Shale wells and has been able to reuse virtually all of the water for industrial purposes, according to a company spokeswoman. "None of these [methods] are going to stop development," says Stevens. "[Natural gas] is still going to be a very attractive investment" for its low costs and proximity to end-use markets.