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The Obama administration wants to clamp down on shale gas drilling on public lands and set standards that proponents of tougher regulation hope will provide a blueprint for drilling oversight nationwide.

Industry sources said the Interior Department could propose a new rule on hydraulic fracturing, or fracking, as early as Friday.

The measure would require natural gas drillers to disclose chemicals they use to frack wells, a controversial process that involves injecting water, sand and chemicals deep underground to extract fuel from rock formations.

Fracking has been essential to unlocking the nation’s massive shale gas reserves, but critics argue that the practice has polluted water and hurt the environment.

The administration has said it supports shale oil and gas development, but has also called for strong oversight.

Administration officials have said they hope the rules could provide a template for states, which handle most of the regulation of fracking.

The Bureau of Land Management estimates that companies use the fracking technique on about 90 percent of wells drilled on federal lands. But only about 14 percent of U.S. natural gas production occurred on those lands in 2010.

An Interior Department official, who did not speak for attribution, said the administration has been clear about its aim throughout the process.

“We intend to propose a rule that supports the administration’s goal of continuing to expand production of America’s abundant oil and gas resources on federal and Indian lands by taking steps to ensure public confidence in hydraulic fracturing and other technologies that will play an integral role in our nation’s energy security.”

Industry and other stakeholders will have a chance to comment on the draft before it is finalized.

A draft of the rules that leaked in February proposed that companies disclose the “complete chemical makeup of all materials used” in fracking fluids, a provision that has been opposed by industry.

That draft plan also would require drillers to ensure the stability of underground casing in wells and that waste water from fracking does not leak into the environment.

The Environmental Protection Agency late last year issued a draft study that said fracking fluids likely polluted an aquifer that supplies public drinking water in Wyoming.

The energy industry has complained the draft rules were overkill as companies were voluntarily revealing the fluids.

One of the largest natural gas drillers, Chesapeake Energy Corp, said it has been voluntarily disclosing its information on chemicals for nearly a year on all its wells on public or private lands on the Web.

Other major producers include Exxon Mobil, Chevron, and Range Resources.

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Sitting at a construction yard along Houston’s Ship Channel is a 35-foot-tall, 100-ton hunk of steel that its owners hope never to use.

The device is BP’s new capping system, designed to halt gushing crude from damaged deep-water wells. It joins other subsea containment systems designed for the Gulf of Mexico and other parts of the world, including Angola and the North Sea.

But unlike systems offered by Helix Well Containment Group and the Marine Well Containment Co., BP’s device is engineered so it can be flown to subsea wells around the globe.

The $50 million capping system package – along with an assortment of tools that were designed to go along with it – was completed in August. BP gave reporters a glimpse on Thursday, before planned maintenance and testing.

Richard Morrison, a vice president in charge of BP’s global deep-water response, said the oil giant tapped expertise honed during the April 2010 Macondo well blowout to devise the system.

Engineers considered the system ultimately used to contain the Macondo well in creating similar devices. Workers who were part of the subsea response in 2010 told BP what other items needed to be in the toolkit, including heavy-duty wrenches, grinders and debris-clearing equipment.

“There are 1 million plus details to get this out of the shop and into a response,” Morrison said.

BP workers also have had to think through possible scenarios for deploying the equipment, including how to position and balance components inside cargo planes and move it at various airports.

Response plans have been developed for all areas where BP is doing deep-water drilling, said Geir Karlsen, BP’s containment response system team leader, adding: “There’s more to this than sending a kit to a region and then figuring out how to use it.”

The system, which is sitting at an ASCO warehouse along the Ship Channel in East Houston, is made up of three main pieces, including a lower section that can sit on the wellhead, or atop other devices at the site.

An upper assembly has two gate valves that can close to block gushing hydrocarbons.And a flow-back system can funnel oil to a vessel at the surface if shutting in a wild well risks devastating damage to the reservoir.

Common elements

The system is built with many standard parts common in the industry. For instance, the lower section is an off-the-shelf Cameron production tree with custom modifications. The upper piece is essentially two gate valves with a connector.

BP is a member of the Marine Well Containment Co., the first line of defense for the Gulf of Mexico. Although BP’s new system isn’t designed for use in the Gulf, the company said it could serve as a backup there in case other options failed. U.S. regulators now require companies to prove they have the equipment and ability to contain blown-out wells before giving approval to drill in deep water. BP also has another well cap system for use specifically in Angola.

BP estimates it could take up to 10 days to get the system displayed Thursday to the most distant drill sites, such as off the coast of Australia. But for other areas, such as the coast of Brazil, the containment cap could be in place within five to seven days. Chemical dispersants and other tools would be on the first planes, to clear debris and keep oil at bay so ships can safely intervene.

Why it’s in Houston

All told, it would take about 35 trailer loads to transport the equipment to five Russian cargo planes and two Boeing B747-200s that could fly it around the world. For now, keeping the equipment in Houston makes sense because of relatively easy access to cargo planes that fly in from Dubai and engineering expertise in the region.

BP plans to put the well cap through emergency tests next year.

Morrison stressed that BP’s focus is on preventing another spill.

“You’re building all this capability, you’re thinking through all the scenarios,” he said. “But you’re also thinking, well, if the prevention guys do their job, I won’t ever have to deploy this.”

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Natural gas is getting cheaper, but diesel and gasoline are not. That holds major implications for businesses that burn a lot of fuel, and also a lesson for other enterprises.

The natural gas price decline is a result of two factors: tremendous success by natural gas exploration and development companies, and the difficulty of transporting natural gas over oceans. When the price of energy rose, oil and gas companies stepped up their exploration efforts and developed new technology. They were very successful at finding natural gas in North America. However, natural gas has a problem: you cannot carry it in a bucket. The high cost of sea-going transportation makes natural gas a continental market. So natural gas has become cheap here, while oil is expensive all over the world. Oil is a global market because intercontinental transportation is fairly cheap.

If you run a fleet of local delivery trucks, or other equipment burning diesel or gasoline, consider switching to compressed natural gas (CNG). This doesn’t work well for over-the-road trucks, because of the lack of refueling stations. If your cars, trucks or forklifts come home every night, then CNG may be for you. One farmer has even converted his tractor to run on natural gas—because he’s got a gas well on his property. It probably would not make sense to pay for construction of a new pipeline to your business. (Other issues to consider include how much space on the vehicle can be allocated to fuel storage—it will take more space to get the same range as you now get with diesel or gasoline.)

Before spending money upfront on the conversion, you need to consider the forecast for liquid fuel prices versus natural gas. My own outlook is for natural gas to stay cheap for at least this decade. Only if we develop extensive export facilities will we see natural gas priced comparably to diesel and gasoline.

For businesses that do not burn a lot of fuel, here’s the lesson from this article: when relative prices change, best business practices change. We economists talk about inflation when most prices are moving up and down together. We say “relative price change” when the ratio of one price to another moves up or down. Whenever there is a relative price change, look for ways to use more of the cheaper good and less of the more expensive good. That sounds obvious, but it’s easy to think that the way you’ve been doing business is the only way. Considering relative price changes should be on every company’s annual planning checklist.

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Natural gas prices jumped 4 percent Thursday after a government report eased concerns that the U.S. could run out of room to store its expanding supply of the fuel. Oil prices moved in the opposite direction, falling 2.5 percent on concerns about U.S. economic growth.

Natural gas futures have rebounded from 10-year lows as supplies fall more in line with average levels for this time of year. The government’s latest report said U.S. natural gas supplies rose by 28 billion cubic feet last week, below the 30-34 billion cubic feet that analysts had expected.

The price of natural gas futures added 8.7 cents to end the day at $2.34 per 1,000 cubic feet in New York.

Analysts warned earlier this year that a glut in natural gas was in danger of swelling to a point where the U.S. would run out of storage. Natural gas producers such as Chesapeake Energy Corp., Encana Corp. and ConocoPhillips responded by shutting down some natural gas operations.

Those efforts are starting to make a difference, said independent analyst and trader Stephen Schork.

Supplies are still nearly 50 percent higher than average for this time of year, according to the Energy Information Administration. But they were more than 60 percent above average earlier this year.

Meanwhile, oil prices fell on a batch of reports that raised concerns about U.S. economic growth. The Institute for Supply Management said service companies expanded more slowly last month. And Costco, Macy’s and Target reported disappointing April sales.

“The demand picture just isn’t very good,” said Peter Donovan, a broker with Vantage Trading.

Benchmark West Texas Intermediate crude dropped $2.68, or 2.5 percent, to $102.54 per barrel. Brent crude, which helps set the price for oil imported into the U.S., lost $2.12 to $116.08 per barrel in London.

Analysts noted that U.S. oil supplies have hit a 22-year high in Cushing, Okla., where benchmark West Texas Intermediate crude is delivered. And world oil supplies could be rising as well.

Reuters reported Thursday that OPEC is producing 2.3 million barrels per day above its targets in an effort to push international oil prices back toward $100 per barrel.

The New York Mercantile Exchange also made it more expensive for some traders to buy commodity contracts.

The CME Group, which owns the Nymex, said new federal trading rules directed it to increase the amount of money that certain speculative investors need on hand to buy futures contracts. The increase will likely undercut the amount of contracts they can buy, analysts said, and that tends to weigh on oil prices since a majority of speculative trades are bets that prices will rise.

At the pump, retail gasoline prices in the U.S. were flat at a national average of $3.803 per gallon, according to auto club AAA, Wright Express and Oil Price Information Service. A gallon of regular unleaded has dropped by 13.3 cents since peaking in April at $3.936. Gasoline is also 16.4 cents per gallon cheaper than the same time last year.

In other futures trading, heating oil gave up 5.56 cents to finish at $3.0869 per gallon while wholesale gasoline lost 2.57 cents to end at $3.05 per gallon.

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Policymakers should let the market decide whether U.S. should export more natural gas, and how much.

The recommendation comes in a policy brief titled “Liquid Markets: Assessing the Case for U.S. Exports of Liquefied Natural Gas,” released May 2 following a year-long study by the Energy Security Initiative at the Brookings Institution.

The study addresses the growing debate on exports as an outlet for growing U.S. natural gas supply.

Eight proposals now at various stages of federal approval would liquefy natural gas for export, the report notes.

Opponents to such projects argue that increasing exports of liquefied natural gas, or LNG, will raise domestic gas prices unnecessarily, the report recounts; proponents argue that it would bring valuable foreign exchange and promote economic growth and job creation.

The report’s authors conclude that increasing LNG exports is feasible and that some amount of U.S. LNG would be competitive in global markets.

Exports are likely to have only a modest upward impact on prices, they conclude. This is consistent with a U.S. Department of Energy study projecting increases of 3 to 9 percent.

That modest the price increase would, in turn, likely have only a limited impact on the competitiveness of U.S. industries that rely on gas, the authors wrote.

They found that LNG exports could make a modest positive contribution to the nation’s gross domestic product and its trade balance.

With regard to climate change, the report reviews factors that offset each other with an unclear net effect.

Increased gas extraction would mean increased volume of leaks and emissions of greenhouse gases, the study acknowledges. And if LNG exports generated electricity that would otherwise have been generated by nuclear or renewable power plants, that would increase greenhouse gas emissions. On the other hand, if the exports decreased the generation of power from coal, they would reduce emissions.

Whether LNG exports increase or reduce climate-warming emissions, the authors conclude, the volume would be negligible.

Positive effects on international relations are seen.

“There is potential for positive foreign policy impacts from U.S. entry in the global gas market through both increased supply diversity for strategic gas-importing allies, and as a contributory factor in weakening the oil-linked contract pricing structure that works to the advantage of rent-seeking energy suppliers,” the report reads.

The authors ultimately recommend that policymakers refrain from either promoting or limiting LNG exports.

“The nature of the LNG sector, both the costs associated with producing, processing, and shipping the gas, and the global market in which it will compete, will place upper bounds on the amount of LNG that will be economic to export,” the report reads.

“Efforts to intervene in the market by policymakers are likely to result in subsidies to consumers at the expense of producers, and to lead to unintended consequences,” it reads. “They are also likely to weaken the position of the United States as a supporter of a global trading system characterized by the free flow of goods and capital.”

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Western state officials took turns bashing the federal government Wednesday at a congressional field hearing on proposed nationwide drilling rules on hydraulic fracturing.

The field hearing by the Subcommittee on Energy and Mineral Resources was called in response to last month’s announcement by the Obama administration that it would seek coordinated federal oversight of natural gas production. The Interior Department, meanwhile, is expected to issue new rules in the next few weeks on natural gas drilling on public lands

The federal oversight was denounced by officials from Colorado, Wyoming and Utah, all of which rely heavily on oil and gas production.

“We have a knee-jerk reaction in Washington that the federal government needs to be in charge and be in control, and I couldn’t disagree more,” said Kathleen Clarke, director of the Utah Office of Public Land Policy Coordination.

Shawn Reese, policy director for Wyoming Gov. Matt Mead, testified that 20 percent of that state’s workforce is tied to energy production.

“The importance of natural gas to the state’s economic situation cannot be overstated,” said Reese, who said federal oversight would be “unnecessary and unreasonable.” Wyoming was one of the first states to require companies using fracking chemicals to disclose the ingredients in those mixtures to state oil and gas regulators.

Colorado Rep. Doug Lamborn, a conservative Republican who heads the subcommittee, introduced the hearing by blasting the Obama administration and the U.S. Department of Interior for trying to “hijack” state oversight of drilling practices including hydraulic fracturing, also called fracking.

Fracking involves blasting mixtures of water, sand and chemicals deep underground to stimulate the release of gas. It is often combined with horizontal drilling, which can increase production far beyond a vertically drilled well.

“This administration’s anti-energy policies continuously hinder rather than help job creation and energy production,” Lamborn said.

But the Washington-bashing session quickly veered off script when two Democrats on the panel, and a citizen fracking opponent called to testify, blasted suggestions that there’s no need for national health and safety regulation.

“Do Coloradans react differently to water pollution?” asked a skeptical Rep. Rush Holt, a New Jersey Democrat who attended the field hearing and questioned the state officials who argued against national safety regulation. After Clarke testified that Utah saw no water contamination in 50 years, Holt said that perhaps that was because the state wasn’t looking.

The subcommittee also heard from a Colorado mom who has tried unsuccessfully to block a gas drill planned within 600 yards of her daughter’s elementary school.

Jen Palazzolo of Erie, a suburb about 30 miles north of Denver, testified that state officials haven’t been any more helpful in her fight.

“As a mother who wants nothing but to protect my children, I ask myself every day if we know enough” about fracking, Palazzolo said.

Democratic Rep. Diane DeGette of Denver, who has sponsored unsuccessful bills seeking required disclosure of fracking fluids used by energy companies, argued that all levels of government, including municipalities, should have a say in how and where drilling is done. She pointed out that technological advances in direction drilling and fracking have brought the drilling procedure closer to populated areas, triggering a need for more governmental oversight.

“We’re drilling in a lot of places with hydraulic fracturing where we weren’t before,” DeGette said.

The question of who sets drilling rules is especially prickly in Colorado. Later in the day, many of the witnesses who appeared before the congressional panel testified at a state legislative panel where the chairman has proposed punishing local governments that seek to rein in drilling. That bill was delayed a second time Wednesday by a committee divided on the idea.

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“Energy independence,” long an empty promise gladly served up by crafty politicians eager to curry favor with unwitting voters, might be a lot closer than even the most starry-eyed dreamer could have imagined only a short time ago.

The country is in the grip of what has rightly been called the “shale energy revolution.” It is a revolution because it overthrows the existing order and casts aside long-standing assumptions about America’s energy future. It’s all about shale — fine-grained sedentary rock composed of mud, clay and silt — and our newfound ability to convert it to affordable energy.

In the space of a few short years, the United States has become the world’s largest producer of natural gas. In 2000, shale accounted for just 1 percent of U.S. natural-gas supply. By 2011, it was 25 percent, and by 2030 it could easily be 50 percent or more. Once burdened with some of the highest natural-gas prices in the world, the United States is now a low-cost producer of a fuel that provides Americans with roughly 25 percent of their electricity.

Hydrocarbons exist in plentiful amounts in the extremely low-permeability — or tight — shale beds that underlie much of the United States, but these resources were not economically recoverable. What has changed is our ability to get at them and extract them in a commercially viable and environmentally responsible fashion. Two companion technologies — multi-staged hydraulic fracturing and horizontal drilling — have made this possible.

Hydraulic fracturing, commonly known as “fracking,” was first employed in the late 1940s and has undergone significant refinements over the decades. It involves injecting water, usually mixed with high-viscosity additives, at high pressures into either oil or gas wells. This result is a fracturing of the rock in the wells, unlocking the gas and oil resources contained in the shale.

Horizontal, or directional, drilling is a substantial improvement over traditional vertical wells, because it enables one rig to extend its drilling activity in several directions simultaneously. When the global price of oil quadrupled is less than a decade’s time, the previously expensive practice of horizontal drilling suddenly made economic sense in shale reservoirs. The more holes that were drilled horizontally, the cheaper and more reliable the process became. More sophisticated steering equipment was developed, better drill bits were fabricated and state-of-the art drilling rigs were built to handle the more challenging conditions of operating within a 20,000-foot-deep hole.

More than a million wells have been “fracked” since the technology was introduced more than six decades ago. Fracking takes place a mile or more below drinking-water aquifers and is separated from them by thick layers of impermeable rock. While concerns have been raised about the water that flows back to the surface after fracking has taken place, here, too, experience and innovation are leading the way in dealing with “flow back.” Additives containing the BTEX-family of chemicals have been eliminated from the product lines used in fracking. BTEX — benzene, toluene, ethylbenzene and xylenes — are the volatile organic compounds found in petroleum. And diesel, once a staple in fracking, has been replaced by much more environmentally friendly mineral oil. Technology doesn’t stand still. Today’s innovations, which are making fracking cleaner and safer, will be superseded by tomorrow’s breakthroughs.

States with energy-rich shale formations are now developing regulations to guide the extraction of oil and gas. In Ohio, for example, Gov. John Kasich, the state legislature and the state’s Department of Natural Resources are working on a regulatory structure that will enable the state to take advantage of the abundant oil and gas contained in the Utica Shale. States have taken the lead in regulating fracking and related energy-extraction practices — and rightly so. The geology and hydrology of shale formations not only differ from state to state, they vary widely within the states. As noted by the Pennsylvania Department of Environmental Protection, which has years of experience overseeing fracking in the Marcellus Shale, the exact “blend” and proportion of additives used in hydraulic fracturing “will vary on the site-specific depth, thickness, and other characteristics of the target formation.” This is not a practice that lends itself to a national, one-size-fits-all regulatory approach administered by the federal Environmental Protection Agency.

Innovation and intelligent state regulation of fracking are already starting to put some glitter back into the Rust Belt. Youngstown, Ohio — all but written off a few years ago — is on the rebound thanks to the Utica Shale. Human ingenuity, and the prosperity it brings, might yet lead the United States to energy independence.

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Devon Energy Corp. (DVN) is open to inviting partners into its oil and gas operations in order to share the risk of developing them, Chief Executive John Richels said Wednesday.

“We could easily pursue these opportunities on our own,” but joint ventures can “accelerate activity, improve capital efficiency and mitigate risk,” Richels said in an earnings conference call.

In the second quarter, Devon expects to produce between 685,000 and 695,000 barrels of oil equivalent per day on average, said Jeff Agosta, Devon’s Chief Financial Officer, who added that production is likely to grow in the second half of the year as growth in oil and natural gas liquids outpaces decline in natural gas production. The company is on track to having 40% of its total output be in the form of hydrocarbon liquids by year end, Agosta said.

Devon’s earnings came below expectations in the first quarter mainly because Canadian crude traded more cheaply than expected as refiners simultaneously performed plant turnarounds. The differential between Canadian crude and West Texas Intermediate crude, however, is quickly narrowing, Agosta said, having come down to $26 per barrel in May from $48 per barrel in March.

Natural gas liquids are also seeing price weakness versus WTI crude due to turnarounds in petrochemical plants in the U.S. Gulf Coast. Devon expects natural gas realizations in the second quarter to average 32% to 38% of WTI prices, Agosta said. In the second half of the year, NGLs are expected to trade at 34% to 40% of WTI prices, he added.

Marketing and midstream profits in the next quarter are expected to come $50 million below the previous guidance, Agosta said.

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