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The Louisiana Oil and Gas Association (LOGA) met on Thursday, Feb. 16 to confront the big issues surrounding the oil and gas industry.

Topics such as fracking, offshore drilling and President Obama’s plan to move to cleaner energy were talked about.

The meeting was part of an effort to educate local professionals on the current state of Louisiana’s oil and gas industry.

President of LOGA Don Briggs said business in the Gulf of Mexico will pick back up.

“The Gulf still today has some of the most productive potential resources in the entire world,” Briggs said.

Briggs said the Gulf moved down from an 11^th place position to a 60^th place in terms of “drilling attractiveness” because of the uncertainty that was created in the Gulf from the President’s Moratorium. And Briggs believes it will come back.

“There are 42 rigs out there right now,” Briggs said. “Several companies are bringing rigs in, so I think we’re going to see that continue on.”

The current 42 rigs in the Gulf compared to the 148 rigs back in 2001, and Briggs said the Obama Administration’s efforts to bring back the Gulf are insufficient, focusing more on cleaner energy like wind and solar. But Briggs said cleaner energy is not going to fuel the engine for the country.

“In his new budget he [Obama] says they’re tired of subsidizing the domestic oil and gas industry when in fact, they don’t subsidize our industry. We have investment incentives we get like depreciation and other things that all businesses get, so we’re not subsidized by any means,” Briggs said.

But overall, Briggs said the state is in good shape when it comes to bringing back the oil and gas industry.

“We’re always going to be in the energy business. But that’s the wonderful thing about living here and in your community, and in South Louisiana, and in the state, is that we’re an energy business and we have so much. They’re always going to need us,” he said.

The next LOGA meeting is Monday, February 27 at the L’ Auberge Casino.

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The oil and gas industry has made technological strides in recent years, but exploration and production are threatened

by government regulation and by lawsuits, a trade group leader said Thursday.

“We are at a major point in the oil and gas industry,” said Don Briggs, president of Louisiana Oil and Gas Association. “We are right in the middle of history being made.”

The United States — the world’s No. 3 oil producer and No. 1 consumer — imports 47 percent of its crude oil, he told a lunchtime

audience at Reeves Uptown. If the U.S. were ever to go to war with Iran, gas prices would rise to $200 a barrel, Briggs said.

He criticized President Barack Obama’s efforts to end oil and gas industry subsidies and offer cleaner energy tax credits, and he said one of his biggest worries is the U.S. Environmental Protection Agency “getting control of hydraulic fracturing.”

Hydraulic fracturing involves injecting water and chemicals into underground shale formations to release trapped gas. The EPA has linked the practice to groundwater contamination.

‘Big game changer’

The oil and gas industry is being “revolutionized,” Briggs said. The technology involved in hydraulic fracturing and lateral

drilling have changed the domestic oil and gas industry — increasing the drilling depth from 200 to 4,000 feet, he said.

Briggs said this technology is a “big game changer” and has made shale exploration so successful. The Haynesville Shale, in north Louisiana, is the nation’s highest-producing natural gas field, he said.

“I can’t begin to tell you the billions upon billions of dollars involved with that,” he told the audience. “The economic impact is

tremendous.” Even though prices have fallen dramatically over the last couple of years, Briggs said, North America is the investment hot spot for natural gas exploration.

He referred to Louisiana as “The Energy State,” and he said a lot of that energy stems from Lake Charles. He said it’s important that we export natural gas from Louisiana. “You have to let the free market work,” he said.

‘Legalized extortion’

Briggs said the legal environment in Louisiana troubles him. More than 200 lawsuits over the environmental effects of drilling have been filed, he said, and 1,500 are pending.

He talked about a 2003 state Supreme Court decision that awarded Shell Oil Co. to pay a landowner $33 million to cover cleanup costs.   The value of the property was estimated at $108,000, he said.

He said 56 percent of the top 50 producers face “legacy suits.” “We’re getting sued for what was legal back then,” Briggs said.

“It’s what we call legalized extortion.”

The LOGA annual meeting will be Feb. 26-28 at L’Auberge. To register, visit www.loga.la .

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The world’s largest money manager has increased its stake in several companies that stand to make a lot of money if drilling in the Lower Smackover Brown Dense oil formation in south Arkansas and north Louisiana proves successful.

According to filings made public Monday by the U.S. Securities and Exchange Commission, New York City-based BlackRock Inc., which has $3.5 trillion in assets under management, in December increased its holdings to 5.66 percent of Southwestern Energy Co. outstanding stock and nearly 6 percent of Cabot Oil & Gas Corp.’s stock. Both Houston-based companies are drilling in the Brown Dense.

Southwestern has more than 347 million shares outstanding, while Cabot had 104.2 million shares outstanding as of its annual stockholders meeting last year.

Southwestern Energy, the top producer in the natural-gas producing Fayetteville Shale of north-central Arkansas, announced in July that it had spent $150 million leasing about 500,000 acres in south Arkansas and north Louisiana. Steve Mueller, chief executive officer at Southwestern, said last week that there could be 3 billion barrels of recoverable oil underneath that 500,000 acres.

If true, it could be a significant development for oil exploration in the U.S.

“For the industry, the Brown Dense is another large potential play that could add a meaningful amount of oil reserves in the U.S.,” Raymond James energy analyst Andrew Coleman said.

The Brown Dense is part of the old Smackover formation, which in the 1920s produced one of the first U.S. oil booms.

The companies are hoping horizontal drilling and hydraulic fracturing, or fracking, will allow them to tap the Brown Dense. The technique has unlocked vast amounts of oil and natural gas in formations around the U.S.

Fracking is the process of injecting millions of gallons of water, mixed with sand and chemicals, into a well to release minerals from a formation. Besides Southwestern and Cabot, Devon Energy Corp. of Oklahoma City and Irving, Texas-based XTO Energy, a subsidiary of Exxon Mobil, are drilling in the Brown Dense.

In addition to Southwestern and Cabot, BlackRock bought a 5.4 percent stake in Exxon. However, Exxon has operations all over the world, making it harder to tell whether the purchase is Brown Dense related, analysts said.

BlackRock also bought 7.23 percent of El Dorado-based Deltic Timber Corp. stock, which has leased

14,000 mineral acres to companies exploring the Brown Dense. Wellington Management Co. of Philadelphia, one of the largest money managers in the country, also has bought a 7 percent stake in Deltic.

A spokesman for Deltic had no comment Tuesday. BlackRock also bought a 5.73 percent stake in a second timber company, Plum Creek Timber Co. of Seattle, that has about 1 percent, or 7,747 acres, of its 747,000 acres in south Arkansas leased for oil and gas drilling. Federal rules require disclosure when holdings reach 5 percent in a company.

BlackRock bought some shares of Southwestern, Cabot, Deltic and Plum Creek in September, but in December it increased those holdings to more than 5 percent.

BlackRock spokesman Jessica Greaney would not say if the purchases are related to the Brown Dense. However, Coleman thinks there is a connection.

“You’ve got … a growing list of high-quality players in the area, and it sounds like you’ve got a growing list of higher-quality investment funds in the area,” Coleman said. “Where there is smoke, there is fire.”

Still, more information needs to be established before it can be confirmed that there is more than 3 billion barrels of recoverable oil in the Brown Dense.

While Southwestern’s stock price has improved slightly since announcing how much recoverable oil it might be sitting on, the stock has not jumped as much as it will if the Brown Dense is actually economical, said Will Green, an energy analyst with Stephens Inc.

Should the Brown Dense have more than 3 billion barrels of recoverable oil, it would be on par with the Eagle Ford Shale in south Texas and the Bakken Shale, which includes parts of Montana and North Dakota and extends into Canada. The U.S. Energy Information Administration says there are about 3.5 billion barrels of recoverable oil in each formation.

“Investors want to see proof,” Green said. “Proof of not only the first well working, but repeatability. Even in some of these more established oil plays, bigger oil plays like the Eagle Ford, the Bakken or the Permian Basin, sometimes questions linger even after a number of results have been shown.”

Southwestern’s stock opened at $32.90 on Thursday, when Mueller said there could be 3 billion barrels of recoverable oil. On Tuesday it closed at $33.60. The stock has not gone below Thursday’s open since Southwestern revealed the information.

Green said there are early questions about well completion techniques and geological characteristics.

Mueller said Southwestern’s first Brown Dense well in Columbia County is starting to produce, but didn’t say how much oil was flowing.

“I get asked all the time, ‘What would make you excited from a production rate on that well?’” Mueller said Thursday at the Credit Suisse Energy Summit in Vail, Colo. “If we could get a 100-barrel-a-day rate out of this well, I’d be jumping up and down. What you really need to have to make economics work on what we think will be an $8 million well, ultimately, is between 400 and 500 barrels a day.”

Mueller said Southwestern used completion techniques similar to its wells in the Fayetteville Shale, but that for future wells it will use methods that have made the Eagle Ford and Bakken so successful. Mueller said more information about Southwestern’s first well will be available when the company releases its fourth-quarter earnings report Feb. 27.

Meanwhile, Cabot Oil & Gas filed a permit application Feb. 2 with the Arkansas Oil and Gas Commission to burn off natural gas as it tests its well in Union County. Burnoffs are an indicator of ongoing drilling. Cabot has not released any additional information about the Brown Dense and a spokesman did not return a call Tuesday.

Coleman said BlackRock might be buying into the formation early to try to cash in on the potential.

“[BlackRock] certainly has a good reputation for being good stewards of capital and being savvy stock pickers, so they might even be willing to buy in a bit earlier,” Coleman said.

Green, a Stephens analyst based in Dallas, said if the Brown Dense is successful, Southwestern’s stock could improve dramatically.

“If you can meaningfully extract oil from south Arkansas in a play like the Brown Dense, and if it ends up working like they hope it will, then it can really begin to move the needle positively on the margin and cash flow side,” Green said. “At this point all eyes are focused on what could happen.”

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The head of the state’s oil-and-gas trade group gave a “state of the industry” address to more than 200 businesspeople at the South Central Industrial Association’s monthly luncheon Tuesday.

Don Briggs founded the Louisiana Oil and Gas Association in 1992, after nearly 30 years in the business, to address the larger needs of the state’s energy companies.

“He knew that if the industry was going to survive under the onslaught of regulations, it had to get organized,” said Lori Davis, president of Rig-Chem, who introduced Briggs at the luncheon. “He strives to make Louisiana a state where oil and gas can continue to prosper.”

Briggs said during his presentation that the industry still faced challenges, playing for the assembled crowd a clip from President Barack Obama’s January State of the Union address that cast a hush over the diners in the ballroom of the Courtyard by Marriott in Houma.

“Our experience with shale gas, our experience with natural gas, shows us that the payoffs on these public investments don’t always come right away. Some technologies don’t pan out; some companies fail. But I will not walk away from the promise of clean energy,” Obama said in the video. “I will not cede the wind or solar or battery industry to China or Germany because we refuse to make the same commitment here. We’ve subsidized oil companies for a century. That’s long enough.”

Briggs also criticized the administration for reacting to the BP oil spill with a six-month moratorium on offshore drilling. And while Briggs called technological advancements such as hydraulic fracturing and horizontal drilling “a revolution for the industry,” he worried about the perception of hazards involved in those extraction processes.

Environmentalists say it’s possible for fracking fluids and any other contaminants to pollute underground sources of drinking water. The Environmental Protection Agency has reported that this occurred decades ago in West Virginia, and the agency is investigating a similar case in Wyoming.

Briggs said the concern is overblown. He cited a scene from the documentary “Gasland,” which shows a man lighting the water from his faucet on fire, and argued that it has always been true that naturally occurring methane gas can get into water aquifers and the phenomenon was not necessarily caused by fracking.

“My concern is that someone’s going to someday do something they shouldn’t do, and the president is going to say we have to shut it down and that we need to look into this for the safety of the American people,” Briggs said. “I never thought I’d say that, but I never thought a president would shut down all the work being done in the Gulf of Mexico, all that investment.”

Still, Briggs admitted, though the permitting process takes more than three times as long as it used to, the rig count in the Gulf is slowly recovering, and natural-gas drilling is taking off.

“I believe it’s getting better, though I’m very concerned about smaller companies that do shallow-water drilling,” he said.

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Chesapeake Energy Corp., the second- biggest U.S. natural-gas producer, is seeking as much as $12 billion from assets sales and joint ventures to cope with a cash crunch amid rising debt and tumbling gas prices.

The company expects to get $10 billion to $12 billion from transactions including the potential sale of all its oil and gas fields in the Permian Basin of Texas and New Mexico, Chesapeake said in a statement today. The Oklahoma City-based company expects to receive about $2 billion in the next 60 days from two separate transactions involving advance sales of output in Texas and Oklahoma.

The deals will help Chesapeake reduce a net debt load that is twice the size of Exxon Mobil Corp.’s, a company with a market value 27 times larger. Chairman and Chief Executive Officer Aubrey McClendon is facing a $3.5 billion gap this year between cash flow and drilling costs, according to Raymond James & Associates Inc. McClendon, who has been seeking an investment- grade rating since at least 2009, has vowed to cut long-term debt 25 percent by year end.

“This is exactly what Chesapeake had to do given the pretty big cash flow-to-spending gap they are facing,” Kevin Cabla, an analyst at Raymond James in Houston, said today in a telephone interview. Selling more shares to bridge the financing gap “would have crushed the stock even more than it has been.”

28 Percent Decline

Chesapeake rose 2.4 percent to $22.66 at the close in New York. Before today, the stock had lost 28 percent of its value in the past year.

Chesapeake and rival explorers such as ConocoPhillips have been curtailing gas production after an expanding glut of North American supplies drove prices to the lowest in a decade last month. Chesapeake is sensitive to falling gas prices, with every 25-cent decline reducing the company’s cash flow by 5.4 percent, Brian Gibbons, a credit analyst at CreditSights, said in a Feb. 7 note to clients.

Chesapeake’s capital spending has exceeded cash from operations in every quarter since October 2003, according to data compiled by Bloomberg. During the third quarter of 2011, as U.S. gas futures were tumbling 16 percent, Chesapeake swelled its net debt by 18 percent to $11.678 billion.

Gas Price Pressure

“This move is clearly in response to pressures exerted by weak natural-gas prices, its high leverage and high spending plans,” Scott Hanold, a Minneapolis-based analyst for RBC Capital Markets, wrote today in a note to clients. Hanold estimates a $4 billion funding gap for 2012.

Gas dipped to a 10-year low of $2.231 per million British thermal units on Jan. 23. Gas for March delivery fell 1.9 percent to settle at $2.431 per million British thermal units in New York, a 38 percent drop in a year.

The company said its 2012 financial plan will “fully fund” its planned spending for the year and provide additional liquidity for next year.

In the next two months, Chesapeake will receive an up-front payment for future production in the Texas Granite Wash formation. Chesapeake didn’t say who the buyer would be.

The company also plans to sell stakes in a new subsidiary that will hold assets in the Cleveland and Tonkawa deposits in Oklahoma. The transaction would be “similar” to an agreement announced in November when private investors bought shares in a Chesapeake subsidiary that holds Utica Shale acreage.

Hottest Regions

Later in the year, Chesapeake may raise as much as $8 billion from transactions in the Mississippi Lime and Permian Basin, where it’s seeking joint-venture partners, the company said. Chesapeake holds the rights to drill on 1.8 million net acres in the Mississippi Lime, which spans northern Oklahoma and southern Kansas.

For the Permian Basin, where Chesapeake holds 1.5 million net acres, the company said it may consider selling all of the assets “if it receives a compelling offer.”

Chesapeake ought to fetch top dollar for its Permian assets because they are about 80 percent oil at a time when crude is averaging $100 a barrel, Cabla said.

“With oil prices at these levels, this is probably the best time to be getting out of the Permian,” Cabla said. “The Permian is one of the hottest regions right now” for acquisitions.

Previous Permian Exit

In September 2002, McClendon said the company would exit the Permian, drilling instead in lower-cost fields in the Midwest. Fifteen months later, Chesapeake changed course with a $420 million acquisition including wells in the Permian from closely held Concho Resources Inc.

Chesapeake plans to raise another $2 billion selling pipelines and gas-processing plants, oilfield-services operations and miscellaneous investments, according to the statement.

Separately, Chesapeake said it will sell $1 billion of senior notes due in 2019 and use the proceeds to repay bank credit.

Moody’s Investors Service cut its outlook for Chesapeake’s corporate rating today to stable from positive, citing lower gas prices and rising debt. The new offering was rated Ba3, three levels below investment grade and a level lower than Chesapeake’s corporate credit.

Moody’s considers up-front gas-production payments as debt and probably will treat most, if not all, preferred shares sold by subsidiaries as debt as well, according to the statement. The combination of debt and asset sales planned this quarter may raise the company’s debt by $3 billion, Moody’s said.

Exxon Mobil, based in Irving, Texas, is the largest U.S. gas producer.

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“You’ve got horizontal rigs, and you’ve got access to these liquids in the crude oil shales; that’s where you’re going.  That’s where the big money is.” David Dismukes, associate executive director  of the LSU Center for Energy Studies

Last year, the state OK’d a pilot project that allowed Encana Corp. to drill the longest horizontal sections for wells the Haynesville Shale in northeast Louisiana has seen — 7,000 and 8,000 feet instead of the usual 4,600. Encana officials said the longer laterals cut production costs so much the company could make money with natural gas prices of around $3 per thousand cubic feet.

The problem — for Louisiana, Encana and every other energy company and landowner in the Haynesville — is that natural gas prices are now hovering around $2.50 per thousand cubic feet.

“That is a killer,” said Jim Welsh, commissioner of the state Office of Conservation. “When the Haynesville got cranked up in 2008, we were looking at $10 to $12 per mcf (thousand cubic feet). That’s down to $2, I mean, come on.”

Some companies say there’s no reason to spend $10 million or $11 million drilling a well in the Haynesville to produce $2.50 gas when the same investment in the Eagle Ford in Texas or Tuscaloosa Marine Shale in central Louisiana brings in oil worth $100 a barrel, Welsh said.

It costs around $4.50 to $5 to produce a thousand cubic feet of gas in the Haynesville, Louisiana Oil and Gas Association Vice President Gifford Briggs said.

The difference between production costs and prices of natural gas versus oil helps explain why the number of rigs working in the Haynesville is falling.

At the peak in October 2010, there were 148 rigs working in the shale, LOGA records show. Now there are 114.

“You’ve got horizontal rigs, and you’ve got access to these liquids in the crude oil shales; that’s where you’re going,” said David Dismukes, associate executive director of the LSU Center for Energy Studies. “That’s where the big money is.”

Encana spokesman Alan Boras said natural gas prices are the reason that energy companies, Encana included, are spending less on dry gas plays and investing more in “liquids-rich opportunities.”

One of those opportunities is the Tuscalooosa Marine Shale, an oil-bearing formation stretching across the middle of Louisiana. Encana has leased around 270,000 acres in the Tuscaloosa. The Canadian company has 350,000 acres in the Haynesville, and 150,000 to 200,000 acres in the Mid-Bossier, a natural gas formation that lies about 2,000 feet above the Haynesville.

Still, depressed natural gas prices don’t mean Encana will abandon the Haynesville or other shale gas formations.

During the BMO Capital Markets investor conferences in January, Encana Executive Vice President Eric Marsh said the long-term outlook for natural gas remains strong.

“It’s the short term, the next two to three years, that will be the challenge,” Marsh told attendees of the conference.

One reason for the company’s optimism is that the utility industry expects to shut down an estimated 30 gigawatts of coal-fired power generation plants over the next three to four years, Marsh said.

“We think that number is probably at the low end. We think that number could be as high as 60 gigawatts,” Marsh told investors.

Sixty gigawatts is enough electricity to power around 35 million homes.

Dismukes said even 60 gigawatts might be too conservative an estimate.

Utilities could mothball as much as 75 gigawatts of coal-fired generation in the next three to four years, Dismukes said. The amount depends on how rapidly federal regulations, such as cross-state pollution and mercury emissions, are put into place.

Meanwhile, electricity demand is rising in most of the country’s power markets, Dismukes said. The mid-Atlantic and Northeast states are desperate for additional power plants, which will burn gas to generate electricity.

The additional plants and higher electricity usage are expected to increase the demand for natural gas by 2 trillion to 3 trillion cubic feet a year, Dismukes said. The United States is now burning around 22 trillion cubic feet a year.

Marsh told investors that when prices recover, Encana will be ready.

The company’s strategy in the Haynesville calls for longer laterals, some as long as 10,000 feet, and an approach that will allow the company to exploit 4 to 6 square miles of reservoir from a single location, he said.

Encana’s Louisiana Haynesville wells are drilled vertically for 11,000 to 14,000 feet, then horizontally for 4,600 feet or so.

State regulations limit the length of the lateral, or horizontal section, Welsh said. Wells must be drilled inside “units” one-mile, or 640 acres, square. The regulations say the well must end 300 feet away from the unit’s boundaries.

“So if you have two units next to each other, and you own both of them … that’s 600 feet that you cannot produce,” Briggs said.

Putting multiple units together means that Encana doesn’t have to start drilling, stop, pick up and move the entire rig and start over, Briggs said. The cross-unit wells generate tremendous savings as a result.

Marsh said the state’s pilot program allowed the company to drill horizontal sections 7,000 to 8,000 feet long.

Encana believes the longer laterals will allow the company to lower production costs to around $2.75 per thousand cubic feet.

The longer lateral wells also boost production, Marsh said. Encana has a couple of cross-unit wells on the Texas side of the Haynesville producing 35 million cubic feet of gas a day, making them some of the strongest wells in North America.

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