(Reuters) – Brent crude fell briefly below $90 as trade moved to European trading hours on Monday, reversing the modest gains earlier in the day, with concerns about faltering global growth and Europe’s intractable debt crisis hitting investor confidence.

The concerns over a further slowdown in the euro zone economy, which could lead to lower oil demand, overshadowed supply disruptions in the U.S. Gulf due to a storm and in strike-hit Norway.

Brent crude dropped by 93 cents to $90.05 a barrel by 0700 EDT, having briefly touched as low as $89.86. U.S. crude fell 75 cents to $79.01 a barrel.

Oil is on track to post its biggest quarterly fall since the financial crisis in 2008 as the euro zone crisis and weak growth in the United States roil global markets, while ample supply from OPEC has added to the downward pressure on prices.

“Another round of European sovereign debt issues … and bearish fundamentals have already started to weigh on oil prices,” Morgan Stanley said in a research note.

“If OPEC production continues at today’s levels, stocks would build above normal through the third quarter and supply would outstrip demand in 2012.”

European shares and the euro also fell. Investors were skeptical that a June 28-29 European Union summit would make any substantial progress towards tackling the euro zone debt crisis, now in its third year and buffeting Spain, the region’s fourth largest economy. .EU<FRX/>

German Chancellor Angela Merkel agreed on Friday with leaders of France, Italy and Spain on a 130 billion euros ($156 billion) package to revive growth, but resisted pressure for common euro zone bonds or a more flexible use of Europe’s rescue funds.

U.S. STORMS

Before the European market open, U.S. crude and Brent crude were trading higher than Friday’s close as a storm threat shut a quarter of U.S. offshore crude and gas output, while a strike in Norway closed two major fields including benchmark grade Oseberg.

U.S. companies shut oil and natural gas production in the Gulf of Mexico at the weekend as a precaution ahead of Tropical Storm Debby.

Debby has since weakened while remaining the northeast Gulf of Mexico, the U.S. National Hurricane Center (NHC) said on Monday.

The U.S. Gulf of Mexico is home to about 20 percent of the nation’s oil production.

Oil workers in Norway went on strike from Sunday over a dispute on pensions and other issues and shut down the Heidrun and Oseberg fields, which together account for about 9 percent or 150,000 barrels per day of Norwegian oil production.

Oseberg is one of four North Sea grades used to determine Brent prices. A full production shutdown in Norway is unlikely, as the government has the authority to force a settlement if a dispute threatens its most vital industry.

Data published by the IntercontinentalExchange (ICE) on Monday showed that speculators raised their net long positions in Brent crude by 75 contracts to 52,112 in the week to June 19.

Although the increase in bullish bets was minor, it was the first rise after speculators had cut long positions for six weeks in a row.

Original Article

Natural gas prices continued to fall this week, pulling down Encana Corp. shares with them as a looming storage overhang pressured markets basking in an unseasonably warm winter.

Encana, the third largest natural gas producer in North America, has seen its stock battered by steadily declining gas prices, falling to a low of $17.39 per share mid-January from a 12-month high of $25.75 in August 2011.

Shares of the company slid two per cent to close at $19.48 on the Toronto Stock Exchange on Wednesday, falling on natural gas futures which settled at $2.448 US per million British thermal units, down 2.4 US cents.

Yet market confidence in the Calgary-based producer appeared relatively unshaken despite no end in sight for soft pricing and the sudden resignation of a key executive earlier this week.

“Investors are concerned about the macro environment, that’s their No. 1 concern” said Randy Ollenberger, analyst with BMO Capital Markets. “So, not so much (Encana) directly, more just the company that’s exposed to a commodity where no one really sees much opportunity for material upside.”

News Mike Graham, president of Encana’s Canadian division, resigned Tuesday barely caused a ripple in the market after executive vice-president Mike Marsh confirmed his abrupt departure.

Ollenberger noted Encana has one of the lowest operating costs in the industry and boasts a high-quality asset base, although levered to the wrong commodity. The company produced approximately 3.36 billion cubic feet of natural gas per day during the third quarter.

Encana has been manoeuvring its assets to recover from a failed $5.4-billion joint venture with China on its Horn River shale gas project last June, divesting $3.5 billion in assets in the past year.

The company has been focusing capital to build up liquids plays from its dry gas-weighed assets.

Encana has several legacy assets in northwest Alberta and northeast B.C., and has stakes in hot new shale plays such as the Niobrara in Wyoming and Tuscaloosa Marine shale in Louisiana.

While Encana is considered a leader in the use of shale-cracking technologies to reduce costs and increase efficiencies, the market’s assessment of its move into liquids will depend on how the company spent on the leases.

“It really boils down to how much land were they able to acquire and at what cost,” said Phil Skolnick, with Canaccord Genuity.

Skolnick noted much of the market’s view will hinge on next weeks quarterly results and guidance.

Last week credit rating agency Standard & Poor’s downgraded Encana to BBB, just two steps above non-investment grade, because of poor natural gas prices in the near term. The company’s debt to adjusted earnings before taxes was 2.1 times, on a trailing 12-month basis, according to third quarter results.

A corporate decision to proceed with the Kitimat liquefied natural gas project in northern British Columbia could provide a boost to Encana’s sagging shares, providing an outlet for its B.C. gas production.

Apache Corp., the Houston, Texas-based lead on the project, is expected to announce a decision on the $4.2-billion project next Tuesday when it releases the company’s fourth quarter results. Encana, which historically would have released its quarterly results this week or earlier, will release its quarterly information the following day.

“The consensus is that the Kitimat project is going to go ahead, and obviously that provides an opportunity for the partners in that LNG project to access higher-priced markets,” said Ollenberger. “It will significantly improve the economics of the Horn River for companies that have that exposure, so Encana, Apache and EOG are the big beneficiaries there.”

 

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The U.S. is the closest it has been in almost 20 years to achieving energy self-sufficiency, a goal the nation has been pursuing since the 1973 Arab oil embargo triggered a recession and led to lines at gasoline stations.

Domestic oil output is the highest in eight years. The U.S. is producing so much natural gas that, where the government warned four years ago of a critical need to boost imports, it now may approve an export terminal. Methanex Corp., the world’s biggest methanol maker, said it will dismantle a factory in Chile and reassemble it in Louisiana to take advantage of low natural gas prices. And higher mileage standards and federally mandated ethanol use, along with slow economic growth, have curbed demand.

The result: The U.S. has reversed a two-decade-long decline in energy independence, increasing the proportion of demand met from domestic sources over the last six years to an estimated 81 percent through the first 10 months of 2011, according to data compiled by Bloomberg from the U.S. Department of Energy. That would be the highest level since 1992.

“For 40 years, only politicians and the occasional author in Popular Mechanics magazine talked about achieving energy independence,” said Adam Sieminski, who has been nominated by President Barack Obama to head the U.S. Energy Information Administration. “Now it doesn’t seem such an outlandish idea.”

The transformation, which could see the country become the world’s top energy producer by 2020, has implications for the economy and national security — boosting household incomes, jobs and government revenue; cutting the trade deficit; enhancing manufacturers’ competitiveness; and allowing greater flexibility in dealing with unrest in the Middle East.

Output Rising

U.S. energy self-sufficiency has been steadily rising since 2005, when it hit a low of 70 percent, the data compiled by Bloomberg show. Domestic crude oil production rose 3.6 percent last year to an average 5.7 million barrels a day, the highest since 2003, according to the Energy Department. Natural gas output climbed to 22.4 trillion cubic feet in 2010 from 20.2 trillion in 2007, when the Federal Energy Regulatory Commission warned of the need for more imports. Prices have fallen more than 80 percent since 2008.

At the same time, the efficiency of the average U.S. passenger vehicle has helped limit demand. It increased to 29.6 miles per gallon in 2011 from 19.9 mpg in 1978, according to the National Highway Traffic Safety Administration.

The last time the U.S. achieved energy independence was in 1952. While it still imported some petroleum, the country’s exports, including of coal, more than offset its imports.

Environmental Concern

The expansion in oil and natural gas production isn’t without a downside. Environmentalists say hydraulic fracturing, or fracking — in which a mixture of water, sand and chemicals is shot underground to blast apart rock and free fossil fuels — is tainting drinking water.

The drop in natural gas prices is also making the use of alternative energy sources such as solar, wind and nuclear power less attractive, threatening to link the U.S.’s future even more to hydrocarbons to run the world’s largest economy.

Still, those concerns probably won’t be enough to outweigh the benefits of greater energy independence.

Stepped-up oil output and restrained consumption will lessen demand for imports, cutting the nation’s trade deficit and buttressing the dollar, said Sieminski, who is currently chief energy economist at Deutsche Bank AG in Washington.

Cutting Trade Deficit

With the price of a barrel of oil at about $100, a drop of 4 million barrels a day in oil imports — which he said could happen by 2020, if not before — would shave $145 billion off the deficit. Through the first 11 months of last year, the trade gap was $513 billion, according to the Commerce Department. Crude for March delivery settled at $96.91 a barrel yesterday on the New York Mercantile Exchange.

The impact on national security also could be significant as the U.S. relies less on oil from the Mideast. Persian Gulf countries accounted for 15 percent of U.S. imports of crude oil and petroleum products in 2010, down from 23 percent in 1999.

“The past image of the United States as helplessly dependent on imported oil and gas from politically unstable and unfriendly regions of the world no longer holds,” former Central Intelligence Agency Director John Deutch told an energy conference last month.

Arab Oil Embargo

That dependence was underscored in October 1973, when Arab oil producers declared an embargo in retaliation for U.S. help for Israel in the Yom Kippur war. The U.S. economy contracted at an annualized 3.5 percent rate in the first quarter of the next year. Stock prices plunged, with the Standard & Poor’s 500 Index dropping more than 40 percent in the year following the embargo.

Car owners were forced to line up at gasoline stations to buy fuel. President Richard Nixon announced in December that because of the energy crisis the lights on the national Christmas tree wouldn’t be turned on.

Today, signs of what former North Dakota Senator Byron Dorgan says could be a “new normal” in energy are proliferating. The U.S. likely became a net exporter of refined oil products last year for the first time since 1949. And it will probably become a net exporter of natural gas early in the next decade, said Howard Gruenspecht, the acting administrator of the EIA, the statistical arm of the Energy Department.

Cheniere Energy Partners LP may receive a construction and operating permit as early as this month from the Federal Energy Regulatory Commission for the first new plant capable of exporting natural gas by ship to be built since 1969 in the U.S. Houston-based Cheniere said it expects the $6 billion plant to export as much as 2.6 billion cubic feet of gas per day.

Mitchell the Pioneer

The shale-gas technology that’s boosting U.S. natural gas production was spawned in the Barnett Shale around Dallas and Fort Worth by George P. Mitchell, who was chairman and chief executive officer of Mitchell Energy & Development Corp.

Helped by a provision inserted in the 1980 windfall oil profits tax bill to encourage drilling for unconventional natural gas, the Houston-based oil man pursued a trial-and-error approach for years before succeeding in the late-1990s. The fracking method he devised cracked the rock deep underground, propping open small seams that allowed natural gas trapped in tiny pores to flow into the well and up to the surface.

Recognizing that Mitchell was on to something, Devon Energy Corp. bought his company in 2002 for about $3.3 billion and combined it with its own expertise in directional drilling, a method derived from offshore exploration.

Hunting for Oil

Traditional vertical drilling bores straight down, like a straw stuck straight in the earth. Directional drilling bends the straw, boring horizontally sometimes a mile or more through the richest layer of rock, allowing more of the trapped fuel to make it into the well. This slice of rock is like the kitchen, where ancient plants and creatures came under so much pressure that they cooked into natural gas and oil.

The oil boom a century ago tapped reservoirs of fuel that rose out of those layers and got trapped in large pockets closer to the earth’s surface, or used vertical wells that could get out only a portion of the fuel stored in the rock. The new technology has Devon and its competitors hunting beneath decades-old oil plays long thought depleted.

About an hour’s drive north from where Devon’s soon-to-be- completed new glass headquarters towers 50 stories above downtown Oklahoma City, the company is exploring for oil in the Mississippian and other formations, where oil majors once made their fortunes. It’s racing companies such as Chesapeake Energy Corp. and SandRidge Energy Inc. to buy leases and drill wells.

North Dakota Booming

Crude production in the U.S. is already increasing. Within three years, domestic output could reach 7 million barrels a day, the highest in 20 years, said Andy Lipow, president of Lipow Oil Associates in Houston, a consulting firm. The U.S. produced 5.9 million barrels of crude oil a day in December, while consuming 18.5 million barrels of petroleum products, according to the Energy Department.

North Dakota — the center of the so-called tight-oil transformation — is now the fourth largest oil-producing state, behind Texas, Alaska and California.

The growth in oil and gas output means the U.S. will overtake Russia as the world’s largest energy producer in the next eight years, said Jamie Webster, senior manager for the markets and country strategy group at PFC Energy, a Washington- based consultant.

While U.S. consumers would still be susceptible to surges in global oil prices, “we’d end up sending some of that cash to North Dakota” rather than to Saudi Arabia, said Richard Schmalensee, a professor of economics and management at the Massachusetts Institute of Technology in Cambridge.

1.6 Million Jobs

The shale gas expansion is already benefiting the economy. In 2010, the industry supported more than 600,000 jobs, according to a report that consultants IHS Global Insight prepared for America’s Natural Gas Alliance, a group that represents companies such as Devon Energy and Chesapeake Energy.

More than half were in the companies directly involved and their suppliers, with the balance coming at restaurants, hotels and other firms. By 2035, the number of jobs supported by the industry will rise to more than 1.6 million, IHS said. Some 360,000 will be directly employed in the shale gas industry.

The oil boom is also pushing up payrolls. Unemployment in North Dakota was 3.3 percent in December, the lowest of any state. Hiring is so frantic that the McDonald’s Corp. restaurant in Dickinson is offering $300 signing bonuses.

State governments are reaping benefits, too. Ohio is considering a new impact fee on drillers and increasing the tax charged on natural gas and other natural resources extracted, Governor John Kasich has said.

In Texas, DeWitt County Judge Daryl Fowler has negotiated an $8,000-per-well fee from drilling companies to pay for roads in the district, southeast of San Antonio.

Lot of Traffic

“It takes 270 loads of gravel just to build a pad used for drilling a well, which means a lot of truck traffic on a lot of roads that nobody except Grandpa Schultz and some deer hunters may have used in the past,” said Fowler, whose non-judicial post gives him administrative control over the county.

The federal government will see tax payments from shale gas rise to $14.5 billion in 2015 from $9.6 billion in 2010, according to IHS. Over the period 2010 to 2035, revenue will total $464.9 billion, it said.

Manufacturing companies, particularly chemical makers, also stand to win as the shale bonanza keeps natural gas cheaper in the U.S. than in Asia or Europe.

Dow Chemical Co., which spent a decade moving production to the Middle East and Asia, is leading the biggest expansion ever in the U.S. The chemical industry is one of the top consumers of natural gas, using it both as a fuel and feedstock to produce the compounds it sells.

First Since 2001

Midland, Michigan-based Dow is among companies planning to build crackers, industrial plants typically costing $1.5 billion that process hydrocarbons into ethylene, a plastics ingredient.

The new crackers will be the first in the U.S. since 2001, said John Stekla, a director at Chemical Market Associates Inc., a Houston-based consultant.

Vancouver-based Methanex said last month it plans to take apart the idled Chilean factory and ship it to Louisiana to capitalize on natural gas prices.

The shift to increased energy independence is also the result of government policies to depress oil demand.

“Vehicles are getting more efficient, and people who travel won’t be driving more miles,” said Daniel Yergin, chairman of IHS Cambridge Energy Research Associates.

Automakers have agreed to raise the fuel economy of the vehicles they sell in the U.S. to a fleetwide average of 54.5 miles per gallon by 2025 under an agreement last year with the Obama administration.

No ‘Silver Bullet’

The 2008-09 recession helped lower oil demand, and consumption has lagged even as the economy has recovered, said Judith Dwarkin, director of energy research for ITG Investment Research in Calgary. Coupled with higher domestic output, “this has translated into an import requirement of some 15.4 barrels per person per year — about on par with the mid-1990s.”

She cautioned against thinking that rising oil and gas production is a “silver bullet” for solving U.S. economic woes.

Michael Feroli, chief U.S. economist at JPMorgan Chase & Co. in New York, agreed, saying in a Jan. 20 note to clients that oil and gas output accounts for just 1 percent of gross domestic production and isn’t likely on its own to be able to pull the economy into above-trend growth.

Cooling on Wind

Some companies are hurting from the shale gas glut. With abundant supplies making it the cheapest option for new power generation, Exelon Corp. scrapped plans to expand capacity at two nuclear plants, while Michigan utility CMS Energy Corp. canceled a $2 billion coal plant after deciding it wasn’t financially viable. NextEra Energy Inc., the largest U.S. wind energy producer, shelved plans for new U.S. wind projects next year.

Investors also are cooling on wind investment, partly because of falling power prices. T. Boone Pickens, one of wind power’s biggest boosters, decided to focus on promoting natural gas-fueled trucking fleets after dropping plans for a Texas wind farm in 2010.

“Wind on its own without incentives is far from economic unless gas is north of $6.50,” said Travis Miller, a Chicago- based utility analyst at Morningstar Inc. Natural gas for March delivery settled at $2.55 per million British thermal units on New York Mercantile Exchange yesterday.

When Obama lauded increased energy production in his State of the Union speech on Jan. 24, he drew criticism from some environmentalists opposed to fracking.

Waning Confidence

“We’re disappointed in his enthusiasm for shale gas,” said Iris Marie Bloom, director of Protecting Our Waters in Philadelphia. Obama “spoke about gas as if it’s better for the environment, which it’s not.”

Deutch, who headed an advisory panel on fracking for the Energy Department, voiced concern that public confidence in the technology will wane if action isn’t taken to address environmental concerns. The potential positive impact of increased North American production are “enormous,” he said.

Higher U.S. output lessens the ability of countries like Iran and Russia to use “energy diplomacy” as a means of strengthening their influence, Amy Myers Jaffe, director of the Baker Institute Energy Forum at Rice University, and her colleagues wrote in a report last year.

While the U.S. will still have to pay attention to issues such as Israel’s security and Islamic fundamentalism in the Mideast, which could affect oil prices, it won’t have to be as worried about its supplies.

Positive ‘Shock’

Carlos Pascual, special envoy and coordinator for international energy affairs at the State Department, suggested at a Council on Foreign Relations conference in December that the increased production in the U.S. and elsewhere gives Washington more “maneuverability” in using sanctions to deal with Iran and its nuclear aspirations.

The increased U.S. production of oil and natural gas is a “positive supply shock” for the economy and for national security, said Philip Verleger, a former director of the office of energy policy at the Treasury Department and founder of PKVerleger LLC, a consulting firm in Aspen, Colorado.

“We aren’t there yet, but it looks like we’re blundering into a solution for the energy problem,” he said.

 

original article

British oil giant BP posted fourth quarter earnings before the bell on Tuesday.  The company saw profits surge despite falling production and weak downstream operations, and is still dealing with the aftermath of the fatal Gulf of Mexico spill of August 2010.

Replacement cost profit, a measure of earnings correcting for inventories, surged 64.8% to $7.6 billion in Q4.  In a per share basis, BP shareholders earned $40.10; holders of BP’s American Depository shares (ADS) earned $2.41.

BP announced it included the favorable impact of a pre-tax credit worth $4.1 billion related to the Macondo/Gulf of Mexico spill in Q4.

Interestingly, revenues were up only 14.7% to $96.3 billion.  The company’s highly profitable exploration and production unit saw its earnings slide 5.6% to $7.55 billion.  BP’s production, only second to Exxon Mobil’s, fell about 5% to 3.487 million daily barrels of oil equivalent.  On the flip side, BP’s Q4 realized prices for crude oil averaged $101.84, compared with $76.80 a year ago.  Natural gas averaged $5.07, up from $3.98 for the same period a year ago.

BP’s downstream performance was weak to say the least.  Much like Chevron, BP saw its refining profit take a big hit in Q4 given falling margins and lower volumes.  Earnings for the unit fell 41.5% to $564 million.

The company is still involved in myriad lawsuits regarding what many consider the worst oil spill in the history of the Gulf coast.  The explosion of the Deepwater Horizon oil rig, owned by Transocean and operated by BP, cost the lives of 11 men and caused the leaking of about 4.9 million barrels of oil into the waters of the Gulf.  BP actually received $4 billion from Anadarko Petroleum in the quarter, which it deposited in the trust being used to pay for the restoration efforts.

Big oil names like Exxon Mobil and Chevron have had a mixed quarter.  While the biggest oil and gas company by reserves, Exxon, had a stellar quarter, Chevron suffered from weakness in their downstream margins and took the hit on their profits.  Oilfield services companies like Halliburton and Schlumberger fared better, both benefiting from the exploding shale boom in mainland North America.

Shares in BP fell in reaction to Tuesday’s earnings, though.  The stock opened in negative territory and bounced off intra-day lows, but remained well in the red by 11:25 AM, trading down 1% or 47 cents to $46.40.

 

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A pair of senators is urging the White House Office of Management and Budget not to let the Environmental Protection Agency sully the reputation of hydraulic fracturing, or “fracking,” the controversial natural-gas drilling method.

Sens. Mary Landrieu (D-La.) and Rob Portman (R-Ohio) are asking OMB’s regulatory chief to ensure that EPA “reaches sound and well-supported scientific conclusions” when finalizing an explosive draft report that linked fracking to groundwater contamination in a Wyoming region.

“A false-positive link between hydraulic fracturing and groundwater contamination could form the basis for costly new regulation,” they write in a letter sent Monday to Cass Sunstein, who heads OMB’s Office of Information and Regulatory Affairs.

“Unwarranted regulation of hydraulic fracturing could have substantial economic impact on the natural gas industry, the consumers and businesses that rely on it, and the millions of jobs that it directly or indirectly supports,” the senators add.

Landrieu is a prominent Capitol Hill ally of oil-and-gas producers, and Portman headed OMB under former President George W. Bush.

The letter adds a new wrinkle to the furor over EPA’s December draft report that linked the increasingly widespread gas drilling method to contamination in the Pavillion, Wyo., region. 

The preliminary conclusions, if borne out, would dent the petroleum industry’s contention that there’s no evidence to support claims that fracking chemicals are fouling groundwater. 

The study has come under attack from energy industry groups and industry allies who call EPA’s methods sloppy and inaccurate. 

EPA has defended the rigor of the draft study, which it is subjecting to peer review.

But the agency is also warning against using the results to draw broader conclusions about fracking and groundwater pollution, noting that the fracking under review in Wyoming occurred under atypical conditions.

The Pavillion study has arrived as federal agencies are mulling various plans to toughen oversight of fracking even as the administration vows to support continued expansion of natural-gas production.

Fracking involves high-pressure injections of water, chemicals and sand to open up fissures in rock formations that enable trapped oil and natural gas to flow. The method is helping to enable a U.S. natural-gas production boom but bringing concerns about water pollution and other public health threats along with it.

Landrieu and Portman are specifically urging Sunstein to ensure the report is considered a “highly influential scientific assessment” under the Information Quality Act (IQA).

The tag would ensure the report gets the review it deserves, the lawmakers say.

“We respectfully urge you to ensure that EPA follows OMB guidelines for appropriate vetting of this important study,” states the letter to Sunstein, the former Harvard law professor that environmentalists view with a skeptical eye.

The IQA is a very brief statute that was buried in a 2000 appropriations bill that has given outside parties — usually industry groups — an additional avenue to challenge data from EPA and other agencies.

It says federal agencies must ensure the integrity of data they disseminate and allow outside parties to submit petitions for corrections.

 

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Comstock Resources (NYSE:CRK) plans to suspend all operated drilling in the Haynesville Shale by March 2012, as falling natural gas prices continue to trigger major reductions in dry gas drilling in the onshore United States. The company will also cut back total overall spending on drilling in 2012.

Haynesville Shale
The company has 79,000 net acres prospective for the Haynesville and an additional 51,000 net acres of exposure to the Bossier Shale, another dry gas play on its property. The acreage is spread across many different counties in northern Louisiana and eastern Texas.

It has been scaling back development of the Haynesville for several years. The company operated seven rigs in this play in 2010, and then began shifting capital to crude oil and other liquid plays. During 2011, it moved two rigs to the Eagle Ford Shale and released three other rigs working in the Haynesville, ending the year with only two rigs in this play.

The company plans to move the final two rigs working the Haynesville to the company’s recently acquired properties in the Permian Basin.

Despite the reduction in Haynesville Shale drilling, it will still expend significant capital here in the early part of 2012. The company will spend approximately $45 million to drill 5.1 net wells and another $61 million to complete 13.3 net wells. Most of this activity will be on a non-operated basis.

2012 Capital Spending
Comstock Resources revised the 2012 capital budget which calls for spending $458 million to drill 60.6 net wells and complete 19.1 net wells drilled in 2011. The company’s previous plan called for spending approximately $545.0 million in 2012 for drilling and completion activities.

One company increasing capital expenditures in 2012 is Oasis Petroleum (NYSE:OAS), which is active in the Williston Basin. The company expects to spend approximately $884 million this year, compared to between $660 million and $667 million in 2011.

Property Impairment
Comstock Resources will also record an impairment of some of its natural gas properties due to the decline in natural gas prices. The company plans an impairment charge of approximately $61 million or 86 cents per share after tax.

Other Haynesville Shale Operators
Other operators that may announce cuts in dry gas drilling include EXCO Resources (NYSE:XCO). The company announced in November 2011 that it would operate 13 rigs in this play. QEP Resources (NYSE:QEP) is also active in the Haynesville, and previously announced a reduction in drilling here in November 2011.

The Bottom Line
The industry flight from dry gas drilling in the onshore U.S. is gaining traction with Comstock Resources, the latest company to cut drilling in these areas. There is every indication that these cuts will eventually have a meaningful impact on natural gas supply in North America.

original article

IN THE race to shore up energy certainty in the face of peak oil, vastly differing strategies are on the international table.

In his State of the Nation address last week, United States president Barack Obama pinned much of his nation’s future to its vast gas reserves.

Hydraulic fracturing – “fracking” – to extract gas could create 600,000 jobs in America by the end of the decade, Mr Obama said.

“We have a supply of natural gas that can last America nearly 100 years, and my administration will take every possible action to safely develop this energy,” he said.

Exploiting gas is part of an “all of the above” US energy policy that also includes renewables, although critics fear that an economy already geared around fossil fuels will retain the easy option at the expense of renewables development.

Meanwhile, Reuters reported early this week that global renewable energy deals climbed 40 per cent to a record high of US$53.5 billion last year, from US$38.2b in 2010.

Solar, wind and energy efficiency projects took precedence over hydropower for the first time, the agency said.

But global economic strains and manufacturing over-capacity in China could dampen the growth of renewables deals in 2012.

BP estimates that despite the growth of renewables, only 5pc of global energy production will come from renewable sources by 2030 – excluding hydro power.

 

original article

Go ahead and crank up the thermostat if you like. You can easily afford it.

A combination of favorable factors has pushed natural gas bills to their lowest prices in a decade with a strong likelihood that prices will drop further over the next two months, possibly matching a record low price point set in the early 1990s.

“We’re now at record gas production, there’s a challenging economic environment, we have record storage, and a mild winter. At some point, you stand back and say, ‘What else can go right? What else is there?’ ” said Mark Frye, president of Palmer Energy in Toledo and chief consultant for the Northwest Ohio Aggregation Coalition.

“The only thing that could go better for us is a mild summer. That’s about the only thing that’s left,” Mr. Frye added.

Wednesday, the price of a million cubic feet (mcf) of natural gas dropped to $2.38 on the New York Mercantile Exchange.

The last time natural gas prices were that low at the first week of February was 2002, when the Nymex price was $2.28, and analysts consider that an aberration because the economy was in a freeze following the 9/11 terror attacks five months earlier.

The all-time Nymex low price for any month was $1.05 in early February, 1992.

Mike Anderson, director of supply planning for Columbia Gas of Ohio, said what makes the current low price for gas different from 1999 or 2002 is that at those points, the nation’s supply of natural gas was dwindling.

“It’s increasing today,” he said.

Natural gas supplies aren’t merely increasing. By most standards they are practically bursting at the seams.

The federal Energy Information Administration’s latest report on the U.S. natural gas supply, released Thursday, showed there was 2.96 billion cubic feet of gas in the nation’s underground storage sites, up 24.6 percent from a year ago, and up 25.4 percent over the five-year average of 2.36 billion for this time of year.

U.S. natural gas consumption for November, the latest figures available, was at 2.02 billion cubic feet.

That is higher consumption than in any November in the last 10 years.

But even with increased consumption, supplies of natural gas are rising. That is because production is higher than ever.

Between 1973 and 2010, monthly gas production never reached 2 billion. In 2011, monthly natural gas production exceeded 2 billion cubic feet seven times.

What’s behind the decade-low prices is a technological revolution known as hydraulic fracturing, or simply “fracking.”

“On the supply side, it’s the successful unlocking of the shale gas through … fracking. That has caused these very large inventories to fill storage,” said Scott Richter, an energy analyst and portfolio manager for the Westfield Insurance Group in Medina, Ohio.

“The economic meltdown didn’t help. What gas we would have used for industry or housing, has gone into storage. And now we’ve carried this large inventory on our backs because of the slow economy production and the lack of housing starts,” Mr. Richter said.

Fracking has allowed drillers to unlock huge volumes of natural gas contained in the Marcellus shale region — mostly in western Pennsylvania and eastern Ohio — over the last five years.

Nearly 25 percent of the nation’s natural gas supplies come from Marcellus shale.

According to a recent report from investment firm Sanford Bernstein, the Marcellus region is so plentiful, by itself it could supply the United States with natural gas at $5 an mcf for 18 years. But the Marcellus region isn’t solely responsible for the plentiful supply.

Fracking and horizontal drilling techniques are being used in areas of Texas and North Dakota to recover oil from older and previously tapped-out wells, Mr. Richter said.

“The negative effect is when you find this oil, you also get gas. When oil is $100 for a barrel of crude and gas is $2 an mcf, they’ll give the gas away,” he said. “If they can flare [burn] it, they’ll flare it. But the bottom line is, they have no use for it.

“And if you can’t use it, it just keeps building up,” Mr. Richter added.

With a dropping price, natural gas producers are hurting. But consumers are huge winners.

In January, 2006, for example, Columbia Gas estimated the average heating bill for its customers at $280. Last month the average bill was projected at $112.

Rossford resident and Columbia Gas customer Jack Roesler is among those who have profited immensely from the drop in gas prices.

In January, 2006, his gas bill was $212. So he added new windows, insulation, and a new furnace.

He cut his January, 2007, bill to $94.

“With the drop in gas prices I’m not saving so much money anymore,” Mr. Roesler said with a laugh. Last month, he wrote a check for $48 to Columbia Gas.

His December bill was just $47.

Columbia Gas’ January price was 50 cents per 100 cubic feet, but it dropped to 45 cents for February.

Customers like Mr. Roesler could see their bills go even lower in March because there are no real impediments to keep prices from dropping.

“The lowest prices of all time was right around now in 1992 when the price hit $1.05 on the futures market,” Mr. Frye said. “How far can things fall? It’s possible to get to that level, but how likely is that? I don’t know.”

But Mr. Anderson of Columbia Gas said the factors that have created the glut of natural gas make it likely the price will keep falling. And normal relief measures that counter a surplus, such as economic activity or cold weather, are missing.

The economy remains sluggish and the weather this winter is among the mildest in years.

Columbia Gas estimates this winter is 19 percent warmer than normal and 28 percent warmer than last year.

Demand for the utility’s gas is 8 percent less than normal and 21 percent below last year.

Ultimately, the marketplace has to balance itself out, Mr. Anderson said. But that means producers cutting back on monthly production and letting customers pull gas out of storage.

However, that is not happening.

As of Jan. 20, the number of rigs producing gas and oil rose by 18 over the previous week, according to a report by oil field services company Baker Hughes.

Mr. Anderson said for some producers, choking back wells just isn’t an option.

“If I think I need a 15 percent rate of return by my gas well, I will probably keep producing,” he said.

“It’s more economical for me to try to produce it today — even though it’s selling for a very low price — than shut down and restart sometime later. The bigger guys can reduce their production, but the smaller guys, it’s a lot tougher for them to shut down.”

And if the Nymex price drops to $2 an mcf at the start of March, Columbia Gas customers will see a price of below 40 cents per hundred cubic feet, Mr. Anderson added.

How long will it last?

For years, politicians and others routinely made note of the fact that natural gas prices in Michigan were lower than those in northwest Ohio mainly because of Michigan’s large capacity of underground storage and its connections to a natural gas hub in Chicago, which could import lower-cost gas from the Southwest and Canada. Ohio, meanwhile, was forced to use higher-priced gas from the Gulf region via Columbia Gas’ eastern U.S. pipeline network.

But with the development of the Marcellus region, that price disparity has reversed the last two years — even though the amount of natural gas shipped to northwest Ohio from the Marcellus region is next to none.

Mr. Anderson said that what the Marcellus shale gas has done is drive prices down at the Appalachian hub where Columbia Gas purchases its supplies.

“The Chicago hub was always cheaper, but now it’s a higher-price market than the Appalachia market,” Mr. Anderson said.

Biggest question

The biggest question now for analysts, producers, and consumers is how long the natural gas surplus — and the low prices it has created — will last.

In 1999, there was a large gas surplus, which prompted electricity producers to go on a huge building spree of natural gas-fired plants that sucked down huge volumes of gas and quickly turned a surplus into a shortage.

Already, the current glut of gas is tempting electricity producers to look greedily at natural gas once more.

In Sandusky County, for example, an on-again, off-again gas-fired power plant project that was conceived in 2001 and was halted in 2005 was sold last year to American Municipal Power Inc. of Columbus, which renamed it the Fremont Energy Center and put it into full service, operating Monday through Friday from 7 a.m. to 11 p.m.

On Wednesday, American Electric Power of Columbus said it had begun commercial operation of 580-megawatt gas-fired plant in Dresden, Ohio.

It bought the partially finished plant in 2007 from a subsidiary of Dominion Energy.

Mr. Frye said such developments, and the quick change in natural gas from a dearth to a glut in just five years, show that it’s impossible to know how long low prices will last.

“If you went back and looked at 2008, the price was around $8 an mcf and you had an escalating price winter-over-winter. Many were saying we’re going to have tight gas supplies forever,” Mr. Frye said.

“Many of those prognosticators are the same ones saying now, ‘Happy days are here again, the sky is blue, and we’re never going to have rain again.’ ”

 

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