President Obama devoted 6.5 full minutes to energy in his more than 70-minute, annual “State of the Union” address this evening. Several remarks were confounding, such as stating support of the U.S. natural gas industry yet for suspending tax breaks to oil companies: With rare exception, U.S. oil companies are natural gas companies. Also, these tax breaks—or “subsidies,” which is the nomenclature used by the anti-energy—are the same breaks provided to all U.S. manufacturers.

Also, Obama credits the federal government with inventing the U.S. shale-gas industry, while it is widely known that industry veteran George Mitchell did this with private-investment risk and during more than 20 years of prodding technology to make hard rock give up abundant gas.

Here is the excerpt of Obama’s address that pertains to energy.

“…And nowhere is the promise of innovation greater than in American-made energy. Over the last three years, we’ve opened millions of new acres for oil and gas exploration and, tonight, I’m directing my administration to open more than 75% of our potential offshore oil and gas resources. Right now, American oil production is the highest it’s been in eight years. That’s right, eight years. Not only that, last year, we relied less on foreign oil than in any of the past 16 years.

“But with only 2% of the world’s oil reserves, oil isn’t enough. This country needs an all-out, all-of-the-above strategy that develops every available source of American energy, a strategy that’s cleaner, cheaper and full of new jobs. 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. The experts believe this will support more than 600,000 jobs by the end of the decade—and I’m requesting all companies that drill for gas on public lands to disclose the chemicals they use because America will develop this resource without putting the health and safety of our citizens at risk.

“The development of natural gas will create jobs and power trucks and factories that are cleaner and cheaper, proving that we don’t have to choose between our environment and our economy. And, by the way, it was public research dollars over the course of 30 years that helped develop the technology to extract all of this gas out of shale rock, reminding us that government support is critical in helping business in getting new ideas off the ground.

“Now, what’s true for natural gas is just as true for clean energy. In three years, our partnership with the private sector has already positioned America to be the world’s leading manufacturer of high-tech batteries. Because of federal investments, renewal energy use has more than doubled and thousands of Americans have jobs because of it.

“When Bryan Ritterby (a lab technician with Energetx Co.) was laid off from his job making furniture, he said he worried that, at 55, no one would give him a second chance but he found work at Energetx, the wind-turbine manufacturer in Michigan. Before the recession, the factory only made luxury yachts. Today, it’s hiring workers like Bryan who say ‘I’m proud to be working in the industry of the future.’

“Our experience with shale gas—with natural gas—shows us that the payoffs from 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. I will not walk away from workers like Bryan. 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. It’s time to end the taxpayer giveaways to an industry that rarely has been more profitable and (to) double down on a clean-energy industry that never has been more promising. Pass clean-energy tax credits; create these jobs.

“We can also spur energy innovation with new incentives. The differences in this chamber may be too deep right now to pass a comprehensive plan to fight climate change. But there is no reason why Congress should not, at least, create a clean-energy standard that creates a market for innovation.

“So far you haven’t acted. Well, tonight, I will. I am directing my administration to allow the development of clean energy on enough public land to power 3 million homes and I’m proud to announce that the Department of Defense, working with us, the world’s largest consumer of energy, will make one of the largest commitments to clean energy in history, with the Navy purchasing enough capacity to power a quarter-million homes in a year.

“Of course, the easiest way to save money is to waste less energy. So here’s a proposal: Help manufacturers eliminate energy waste in their factories and give businesses incentives to upgrade their buildings. Their energy bills will be $100-billion lower over the next decade and America will have less pollution, more manufacturing and more jobs for construction workers who need it. Send me a bill that creates these jobs.”

–Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

“I think, eventually, the pipeline will be approved.”

The blowout WTI/Brent spread of 2011 has been evaporating—falling to $8 at year-end and at about $11 today—as global and North American oil-price dynamics continue to erupt. Iran is talking about closing the Strait of Hormuz, the U.S. Senate has put the Keystone XL project back on Obama’s “to answer” list and the reversal of the Seaway pipeline is under way.

What gives? We caught up with Andy Lipow, founder and president of Houston-based Lipow Oil Associates LLC, for some expert insight. Lipow has been in the hydrocarbon trading and refining business for more than 30 years, including with Europe-based powerhouse Vitol Group and with Amoco Corp., which is now part of BP Plc.

Oil and Gas Investor: Will the WTI/Brent spread evaporate?

Lipow: Well it’s narrowing and it will continue to narrow, depending on how much take-away capacity comes online out of Cushing over the next couple of years. My expectation is that we’re going to see some periods of narrowing followed by some periods of widening followed by periods of narrowing again as there are a lot of changes happening at different times in supply, demand and infrastructure.

Oil and Gas Investor: What created such a vast spread in the first place?

Lipow: It’s a reflection of a number of things. This past year, we had the conflict in Libya, which removed 1.6 million daily barrels light, sweet crude from the market. That was in conjunction with production problems in the North Sea as well as Kazakhstan and Azerbaijan. Meanwhile, here in North America, we have increasing production of crude oil from both Canada and North Dakota that is trying to make its way to refineries on the Gulf Coast. Well, there is currently no pipeline that goes directly from Cushing (Oklahoma) to the Gulf Coast, so we had to look for alternative routes of transportation, mainly rail and barges.

Oil and Gas Investor: It looked like we ended up with “stranded oil” right here in North America.

Lipow: In this case, I think of stranded oil is sort of like being in the middle of the desert with no means to get out. The oil is waiting for a ride. In North America, the oil already being produced is all moving to market. However, in many cases, it’s not coming out of the ground because the producers are waiting for logistics, meaning truck or rail or transloading facilities to come online. In that sense, you could say production is held back by the lack of take-away capacity. But there is certainly a market for the oil.

Oil and Gas Investor: So, there is yet more North American oil supply that is being held back, waiting for take-away?

Lipow: Well, you’re seeing production continue to increase and as infrastructure comes in, yes, oil production will increase.

Oil and Gas Investor: What encouraged ConocoPhillips to sell its half-interest in Seaway this fall?

Lipow: I think ConocoPhillips saw that Enbridge (Inc.) and Enterprise (Products Partners LP) was involved in a number of projects—Monarch, Double E, Wrangler—that were to bring more oil to the Gulf Coast. ConocoPhillips probably thought at least one of these projects would happen and, when it did, it would decrease the value of Seaway to a potential buyer.

Oil and Gas Investor: Without the reversal of Seaway, ConocoPhillips’ Midcontinent refineries were in better fiscal shape for using WTI-priced crude than the Gulf Coast refineries that use Brent-priced crude?

Lipow: They had a raw-material advantage versus Gulf Coast refiners that are buying crudes linked to Brent.

Oil and Gas Investor: The Keystone XL amendment to the payroll-tax-reduction bill that cleared Congress just before Christmas requires Obama answer on Keystone within 60 days, which would be by late February. Do you think Obama will actually approve it then?

Lipow: I think, eventually, the pipeline will be approved. Of course, there are a lot of political issues around Keystone—from the route to the environmental groups that are against anything that would encourage oil-sands production. But now he has another issue facing him and that is the rhetoric in the Middle East.

Oil and Gas Investor: By Iran?

Lipow: Yes, the threat of the closure of the Strait of Hormuz that would affect one sixth of the world’s oil supply.

Oil and Gas Investor: Anything a WTI/Brent-spread enthusiast should know?

Lipow: The Brent/WTI movement is a result of increases in production and a logistics and distribution system that has been inadequate to move onshore North American crude oil to the refining centers on the Gulf Coast. As that distribution system improves, we’re going to see the Brent/WTI spread change.

Oil and Gas Investor: Is even more midstream capacity or direction of take-away needed based on where production is coming online in North America?

Lipow: If you look at over the next five to 10 years, as oil production increases, we will need more infrastructure.

–Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

The industry posted yet more new horizontal oil and gas-liquids plays.

As 2011 has come to a close, here’s a list of some of the top U.S. oil and gas E&P-industry stories of the past year. Add yours by e-mailing ndarbonne@hartenergy.com.

(+) Mississippi Lime. This horizontal oil play in northern Oklahoma and southern Kansas exploded onto the E&P scene in the spring of 2011 with SandRidge Energy Inc. reporting it had amassed nearly 1 million acres over the Chester, Manning, Meramec and Osage mix of limestone, weathered chert or chat, and dolomite. Chesapeake Energy Corp. later reported it had amassed, well, yet more. By year-end Spanish energy giant Repsol YPF bought into SandRidge’s play in a $1-billion joint venture: $250 million in cash upfront and $750 million in drilling carries.

(+) Utica Shale. Chesapeake Energy Corp. and partner EV Energy Partners LP/EnerVest Management Ltd. reported results in September of an initial four horizontal wells into Ohio’s Utica shale, proving gas-liquids production in that state. Four weeks later, Chesapeake had a letter of intent with a still-to-be-identified company for a $3.4-billion joint venture within its Utica leasehold. Chesapeake and EV are working now to prove the oil window of the play. Ohio Gov. Kasich and team are, well, elated.

(-) The New York Times “Hit Piece.” Both industry and non-industry members were apoplectic this summer about an NYT article that claimed scientifically accepted principles in determining future potential of shale-gas production to be a hoax. This was based mostly on old e-mails among a few critics; there was no industry comment. NYT public editor Arthur Brisbane took issue as well with how the article was handled, concluding a couple of weeks later, “My view is that such a pointed article needed more convincing substantiation, more space for a reasoned explanation of the other side and more clarity about its focus.”

(-, +) The Keystone XL Postponement. President Obama shocked Republicans and Democrats alike in November when announcing he would postpone a decision on permitting the Keystone XL Canada-to-the-Gulf-Coast oil-pipeline project until after the 2012 presidential election. The Senate answered 89-10 shortly before Christmas with an amendment to Obama’s payroll-tax-reduction-extension bill that requires he make a decision within 60 days. After some foot-dragging and tongue-wagging, the House concurred with the amended bill before cutting out for the holidays. The amendment’s authors—Senators Lugar (Indiana), Hoeven (North Dakota) and Vitter (Louisiana)—say Obama can only reject the project if he deems trade with Canada to not be in U.S. interest. We’ll see if there are any rabbits left in the White House hat.

(+) Three Forks 2 Horizontal Discovery. Continental Resources Inc., which founded the horizontal Bakken oil play in 2004 and the horizontal Upper Three Forks (Bench 1) play in 2008, made the horizontal Three Forks Bench 2 discovery in the spring of 2011 with its Charlotte 2-22H. The well tested 1,140 BOE per day, mostly oil, from a 9,700-foot lateral after 30 frac stages on a 26/64-inch choke. The company is determining now whether Three Forks 2 produces independent of Three Forks 1; if so, the potential for oil production from the Bakken petroleum system will grow yet again.

(+) Louisiana Eagle Ford Oil Discovery. Going with almost no notice amongst media or industry analysts, privately held Indigo Minerals LLC reported the horizontal Louisiana Eagle Ford discovery in early December. The Bentley Lumber 34H #1 well in central Louisiana flowed 543 barrels oil equivalent (80% light, sweet oil) during a 24-hour test period. The balance of the BOEs was 1,520-Btu, 11-gallon-per-Mcf gas liquids. It’s planning more of these wells in 2012 and is seeking a joint-venture partner.

(+, -) The WTI/Brent Spread. As onshore U.S. oil production became congested at Cushing, Oklahoma, the price differential between WTI (or Nymex) and Brent (or seaborne oil) soared to as much as $25 in Brent’s favor. The spread has narrowed now to about $8. With oil above $90 for most of 2011, onshore U.S. producers weren’t too disadvantaged; their play economics still worked fine. But the spread wreaked havoc on refiners and fuel retailers—those on contract to buy seaborne crude versus those using cheaper WTI-priced oil. In the Northeast U.S., Brent-fed refineries were closed or have been pegged for closure.

(+) Tuscaloosa Marine Shale. Devon Energy Corp. revealed in May that it was putting its super-independent E&P might behind the bit in this oil-filled, sloughing shale in eastern Louisiana and southwestern Mississippi from which many E&Ps have tried to produce commercially during the past 50 years and failed. The horizontal attempts cost $12 million apiece or more, but the prize upon figuring out how to keep the hole open is large: This shale may contain some 7 billion barrels of oil.

(+) Brown Dense. Southwestern Energy Corp., the founder of the horizontal Fayetteville shale-gas play in north-central Arkansas, revealed in late July that it had put together more than 400,000 acres over the Lower Smackover or Brown Dense formation that is believed to be the source of decades of Upper Smackover oil production. It hasn’t revealed results from two wells in the rock but confirms this: It’s oil.

(+, -) Exporting U.S. Natural Gas. While Washington won’t commit to using abundant new U.S. natural gas supply at home, the Department of Energy permitted Cheniere Energy Partners LP in May to export gas from Cheniere’s Sabine Pass, Louisiana, LNG (liquefied natural gas) receiving terminal to any country with which the U.S. does not prohibit trade. The actual construction of the liquefaction facilities is in the FERC-clearance process now. Washington’s green light to exporting U.S. gas is a win for free markets and monetization of assets to their greatest potential, while also a sad statement on its interest in using this high-Btu, clean and abundant resource at home.

–Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

Energy-company stocks capture investor attention despite year-end portfolio distractions.

Energy-company IPOs have dominated the new-stock scene this month, launching seven of the 13 new U.S.-exchange listings through Dec. 15. The six others capturing investor interest as 2011 wanes and many portfolios are being righted for tax purposes are a social-gaming-service, fashion house Michael Kors Holdings Ltd., a REIT, a social-business software firm and two healthcare-industry operators.

Among the energy IPO pricings this month, onshore-U.S.-focused E&Ps and pipeline operators whet stock-buyers’ appetites.

–Inergy Midstream LP (NYSE: NRGM) priced 16 million units at $17 each. The new natural gas storage and transportation company is a product of John Sherman’s propane-distribution-focused Inergy LP, based in Kansas City, Missouri.

–Randy Foutch’s Laredo Petroleum Holdings Inc. (NYSE: LPI) sold 17.5 million shares at $17 each. Tulsa-based Laredo focuses on oil and gas E&P in the Permian Basin and Midcontinent.

–Michael Starzer’s Bonanza Creek Energy Inc. (NYSE: BCEI) sold 10 million shares at $17 each. Denver-based Bonanza owns oil-producing assets in the San Joaquin Basin of California.

–Randy Olmstead’s Mid-Con Energy Partners LP (Nasdaq: MCEP) sold 5.4 million units at $18 each. Tulsa-based Mid-Con focuses on oil and gas E&P in the Midcontinent.

–Antonio Sanchez III’s Sanchez Energy Corp. (NYSE: SN) sold 10 million shares at $22 each. Houston-based Sanchez has leasehold over Eagle Ford shale in South Texas, over Haynesville in northwestern Louisiana and in Lewis and Clark, Meagher, and Cascade counties, Montana.

–John Weinzierl’s Memorial Production Partners LP (Nasdaq: MEMP) sold 9 million units at $19 each. Houston-based Memorial operates oil and gas properties in South Texas and East Texas.

–Norman Szydlowski’s Rose Rock Midstream LP (NYSE: RRMS) sold 7 million units at $20 each. Tulsa-based Rose Rock owns oil gathering, transportation, storage and marketing assets in Colorado, Kansas, Montana, North Dakota, Oklahoma and Texas.

These IPOs follow several November energy-stock pricings.

–Jonny Brumley’s Enduro Royalty Trust (NYSE: NDRO) sold 13.2 million units at $22 each. Austin, Texas-based Enduro buys net-profits interests in Brumley’s Enduro Resource Partners LLC properties in Texas, Louisiana and New Mexico.

– Eric Mullins and Charles Adcock’s LRR Energy LP (NYSE: LRE) sold 9.4 million units at $19 each. Houston-based LRR has 30 million BOE of proved reserves in the Permian Basin, Midcontinent and Gulf Coast.

–Chesapeake Energy Corp.’s Chesapeake Granite Wash Trust (NYSE: CHKR) sold 20 million units at $19 each. It holds interests in production from a portion of Chesapeake’s Granite Wash-play leasehold in the Anadarko Basin.

–Christian Beckett’s Pacific Drilling SA (NYSE: PACD) sold 6 million shares at $8.25 each. Houston-based Pacific operates ultra-deepwater drillships.

Prior to pricings this week, Gabriele Sorbara, vice president, E&P research, for Caris & Co., forecast, “We believe these transactions will be well received by the market, given their exposure to oily plays, including the Permian Basin, the Eagle Ford shale and Niobrara, to name a few.”

Foutch’s Laredo Petroleum Holdings is particularly eye-catching, “given its exposure to the horizontal Wolfcamp/Cline shales in the Midland Basin. While Laredo’s IPO pricing and valuation should be positive for the Permian players—especially the horizontal Wolfcamp players—we believe this week’s…flurry of IPO activity would bring excitement to the entire E&P sector into year-end.”

–Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

Some participants believe WTI may resume premium pricing.

The WTI/Brent price spread will narrow to between $5 and $10 in 2012, according to 62% of responses from 159 energy-stock buyers and E&P executives in early December in the quarterly “Bernstein Energy Investor Sentiment Survey.”

Another 11% believe the spread will fall to between $0 and $5 in the coming year; 3% believe WTI will exceed that of Brent, possibly by as much as $5, report Bernstein Research senior energy analysts Bob Brackett and Scott Gruber. Meanwhile, 22% believe the spread will range in an average of between $10 and $15, and 3% believe it will be between $15 and $20.

The results are remarkably different than investor sentiment in early September, when more than 70% forecast a 2012 spread of between $10 and $25. A few even expected it to exceed $30.

“With plans of a Seaway (pipeline) reversal announced since our last survey, 62% of respondents now believe the spread will average $5 to $10 per barrel in 2012, with $10 to $15 being the next-most-common response. Only 3% see the spread averaging over $15.”

As for 2014, most of the survey participants believe the WTI/Brent spread will continue to persist to some degree with 76% expecting a range of $0 to $10; however, 14% believe the price of WTI will return to a premium over that of Brent.

“We continue to believe enough pipeline takeaway capacity will be installed or reversed by the end of 2013, and see little to justify a spread in 2014,” Brackett and Gruber report. They note that, until the WTI/Brent blowout this year, the quarterly survey didn’t query participants for their thoughts on the spread.

“We note that our survey has historically focused on WTI crude prices, not Brent, so, to address the current, but shrinking, dislocation, we’ve once again included a question about the spread this quarter.”

–Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

“The Wolfcamp shale play is proving to be oily, consistent and large—very large.”

The oily, horizontal Wolfcamp play may be expanding north of drillers’ current focus in Crockett, Irion, Reagan and Uptown counties, Texas, in the Permian Basin, says Irene Haas, E&P analyst for Wunderlich Securities.

Haas analyzed results of some 30 Wolfcamp wells to date with initial-production rates of 1,000 to 1,500 barrels of oil equivalent (BOE) a day and are up to 60 miles apart.

Sample wells include one by EOG Resources Inc. that tested 1,576 BOE per day in Irion County and one by Pioneer Natural Resources Co., which may drill 80 Wolfcamp horizontals in 2012, that tested 1,200 BOE per day, unrestricted, in Upton County.

Also, El Paso Corp.’s #1H University 43-17 in Reagan County flowed 1,369 BOE per day, mostly oil, from Wolfcamp at 6,700 feet through a 7,500-foot lateral that underwent 25 stages.

“Assuming a 25-mile wide fairway, the trend could cover a 1,500-square-mile area or almost 1 million acres,” Haas says. “…We visited and spoke with a number of Wolfcamp-shale first movers this week and we now believe that the play could expand northward and might not be confined to the four counties.”

Wolfcamp carbonate is a “Lower Permian” play in the neighborhood of Abo, Leonard and Bone Spring carbonates and Spraberry sandstone. Haas believes a Wolfcamp play expansion bodes well for Permian-focused, Fort Worth-based Approach Resources Inc., which tested the deeper C bench of the Wolfcamp with its University 42B #1001H.

In the El Paso well, Wolfcamp is at 6,367 feet; Wolfcamp A, 6,546 feet; and Wolfcamp B, 6,704.

“While Approach did not get to complete all the stages planned, the company is happy with the micro-seismic results and will continue to refine its completion techniques,” Haas says. “We look forward to more wells being drilled in the C Bench, and expect Approach to climb the learning curve quickly.”

EOG, which is drilling Wolfcamp, Leonard and Bone Springs, expects its 240,000 net acres over these will be productive from one or more interval. It also cites Wolfcamp as the biggest of the three and wells there cost as little as $5.4 million each.

“More drilling will need to happen before we know the true extent of this play,” Haas says. “The Wolfcamp shale play is proving to be oily, consistent and large—very large.”

–Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

WSJ interview has the oil industry abuzz about Obama’s hopes for green and alternative energy.

It’s called the Bakken and it has oil superpowers on their heels.

The Wall Street Journal’s Stephen Moore, a member of the Journal’s editorial board, has taken notice too. Moore interviews Continental Resources Inc. founder Harold Hamm in “The Weekend Interview” edition, “How North Dakota Became Saudi Arabia,” Oct. 1. One sign that Moore knows the value of domestic energy supply? Acknowledgement that President Obama’s talk of oil and gas industry “subsidies” is really just the same tax adjustments all U.S. manufacturers receive.

Hamm, whose Continental holds 900,000 net acres prospective for Bakken oil production in North Dakota and Montana, tells Moore the U.S. could be energy independent by the end of this decade, with the right national energy policies.

Hamm, who in 2004 completed the first successful horizontal and multi-stage-fracture-stimulated Bakken well, estimates the oil field may produce 20 billion barrels of oil and 4 billion barrels equivalent of natural gas. Continental alone holds a nearly half-billion of proved reserves—that is, proven to produce—in the oil play. The figure is based on drilling to date, so more could come.

What struck the oil and gas community the most in the week following the Journal report is what Hamm tells Moore of a visit with Obama recently. In this, Obama told Hamm that oil and gas will only be important to the U.S. for a few more years; green energy and battery-powered cars will replace these in importance.

Hamm tells Moore, “Even if you believed that, why would you want to stop oil and gas development? It was pretty disappointing.”

Tom Petrie, vice chairman of Bank of America Merrill Lynch, told Oil Council conference attendees in New York that week, “The unconventional-resource revolution holds great promise for enhancing energy supply flexibility over the next several decades; a U.S. gain of 3 million-plus barrels (of daily production) over the coming decade is possible.”

U.S. oil production grew 3.2% in 2010 from 2009 to 7.513 million barrels a day, according to BP Plc’s annual “BP Statistical Review of World Energy” released in June. The 2009 rate, which was 7.271 million barrels a day, was up from 6.734 million in 2008. In the 2009 review, published in June 2010, BP reported, “U.S. (daily) production increased by 460,000 barrels or 7%, the largest increase in the world last year and largest U.S. percentage increase in our (50-year) data set.”

Peter Tertzakian, chief energy economist and managing director for Calgary-based, energy private-equity firm ARC Financial Corp., said at the Oil Council meeting in New York, “Who would have said two years ago that North Dakota would be an energy superpower?”

The 15,000-square-mile Bakken oil play, which is dubbed a shale-oil play but the oil is actually produced from rock that sits between two shales, is making 400,000 barrels a day already, he notes.

Producers expect—and pipeline and rail operators are gearing up for—making up to 1 million barrels a day from the Bakken in the coming few years.

In the Journal report, Hamm tells Moore, “President Obama is riding the wrong horse on energy.”

–Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

Leasehold in the core Utica play may be worth between $12,000 and $16,000 an acre.

With little drilling—but early play-making results—yet from Ohio’s Utica shale-oil play, Global Hunter Securities LLC’s research team has gathered what is available—even putting Google Earth to work—for an initial “Utipedia” report.

“Uticulous,” says Michael Bodino, GHS managing director and head of energy research, of the first four horizontal completions in the Utica oil window: Each had initial production of more than 1,000 barrels of oil equivalent per day. Chesapeake Energy Corp., in a joint venture with EV Energy Partners LP, indicated in August that the tests confirmed the company has been prescient in accumulating 1.25 million net acres over the shale rock, with possibly some 40% of it in the heart of the play; in late September, it released the test results.

“If the play wasn’t on your radar screen before this announcement, it definitely should be now,” Bodino says.

In compiling the brief “Utipedia,” Bodino and the team compiled 17 slides from 11 producers’ recent presentations that include reference to Utica, which Bodino calls a “potentially massive liquids-rich shale play.”

He estimates leasehold in the core Utica play may be worth between $12,000 and $16,000 an acre in a non-operated, joint-venture structure, which Chesapeake aims to have done by year-end. At $14,000 an acre, here is what these 11 publicly held E&Ps’ leasehold may be worth, he says.

–Rex Energy Corp., 57,900 acres, $811 million or 127% of REXX’s enterprise value.

–EV Energy Partners LP, 159,000 (working interest), 240,000 (royalty interest), $2.23 billion or 77% of EVEP’s EV.

–Gulfport Energy Corp., 57,500 acres, $805 million or 60% of GPOR’s EV.

–Chesapeake Energy Corp., 1.25 million acres, $17.5 billion or 57% of CHK’s EV.

–PDC Energy Co., 30,000 acres, $420 million or 54% of PETD’s EV.

–Range Resources Corp., 357,000 acres, $4.99 billion or 43% of RRC’s EV.

–Magnum Hunter Resources Corp., 16,000 acres, $224 million or 29% of MHR’s EV.

–Hess Corp., 185,000 acres, $2.59 billion or 11% of HES’ EV.

–Consol Energy Inc., 100,000 acres, $1.4 billion or 12% of CNX’s EV.

–Devon Energy Corp., 110,000 acres, $1.54 billion or 6% of DVN’s EV.

–Carrizo Oil & Gas Inc., 1,500 acres, $21 million or 1% of CRZO’s EV.

Bodino adds that Anadarko Petroleum Corp. has an acreage position over Utica but the total leasehold amount is unconfirmed. The Ohio Department of Natural Resources reports Anadarko has received permits for three wells to Utica.

For his full report, click here.

–Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

Chevron Corp. has capex opportunities in the Marcellus, Utica, Monterey

“This is as good as it gets in the deepwater Gulf of Mexico,” says Paul Sankey, Deutsche Bank integrated-oil equity analyst. Sankey and the investment-banking group’s research team visited with Chevron Corp. management Wednesday about the outlook for future meaningful news from the super-major.

“The most dramatic statement from our lunch with Chevron’s consistently impressive board member, senior vice president and head of upstream George Kirkland in Boston…was that current activity levels in the deepwater Gulf of Mexico represent ‘the new normal,’” Sankey says.

President Obama placed a moratorium on drilling under existing permits in the Gulf after the April 2010 Macondo well blowout. The moratorium was lifted later; however, the new regulators of Gulf drilling—the BSEE and BOEM, formerly known as the BOERME that was created and replaced the MMS during the moratorium—has not green-lighted much new drilling under existing permits and new-permit sales were suspended.

“For smaller players—even $9-billion (-market-cap) Murphy Oil Corp. is talking about an exit—this could be the end of the road on red tape,” Sankey says.

If robust drilling is not revived and the only wildcatters left in the billion-barrel Gulf region are mega-cap E&Ps, it is “another nail in non-OPEC (production’s) coffin if this is really peak activity in the GOM, with Chevron and other mega-caps as the only players. Those companies will see fewer competitors, more GOM access opportunities, lower service costs and overall oil prices higher on weak non-OPEC supply,” Sankey says.

He adds, “Good for them; that is, we believe, until the government—of the time, probably mid-next administration—wakes up to low activity, higher unemployment and less U.S. oil supply.”

He adds that Chevron management “stresses that the current regulations are far more onerous—hardly surprising post-Macondo.”

The beneficiary of stranded capex that super-majors planned for the deepwater Gulf includes onshore Lower 48 unconventional-resource plays. Spending on this type of oil and gas development that is still within the U.S. “might mitigate any policy response in Washington.”

Murphy Oil, which he says is considering a Gulf exit, has already stated that it plans to increase spending in the Eagle Ford shale-liquids and -gas play in South Texas.

Chevron plans to increase its capex spending on its Marcellus shale-gas and -liquids assets, which it bought from Atlas Energy Inc. earlier this year. It also holds more than 600,000 acres that are prospective for Utica oil-shale pay in Ohio and it owns a large leasehold in southern California that is prospective for Monterey shale-oil pay.

As for Chevron acquisitions, Sankey says that, in the Wednesday meeting, “denials were not as strong as bulls might hope. Don’t count out more (unconventional-) resource deals here.”

Sankey says cash-rich Chevron is underweight U.S. natural gas and U.S. unconventional resources.

“Questions will persist over its appetite for M&A to boost near-term growth and develop a portfolio with shorter-term, more-flexible spending that the unconventional (play category) offers (compared with long-range Gulf and other mega-projects).”

–Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

“…Additional dry-gas acreage would be met with investor scorn,” says Barclays Capital’s Michael Zenker.

Maybe the ire of investors has publicly held producers shy about buying dry-gas-producing properties. Barclays Capital research analysts asked several public E&Ps’ executives if they would buy dry-gas acreage from distressed sellers today if the price is right.

“Most answered ‘no,’ while only two answered ‘yes,’” says Michael Zenker, Barclays Capital managing director, commodities research. “This suggests that some companies believe adding additional dry-gas acreage would be met with investor scorn. A watershed event would be a company applauded for selling or spinning its gas acreage to focus on oil. Some companies have positioned themselves this way, but have not completely eschewed gas.”

The small-sample survey was taken at Barclays’ recent energy and power conference where more than 170 companies—from E&P and oilfield services to midstream, coal and power generation and transmission—presented to institutional investors in five tracks during three days in New York.

“One company executive indicated that an increasing number of offers to sell gas acreage were being presented to them. In some cases, prices are as low as $1 to $1.50 per Mcf for dry-gas reserves—close to the cost of developing reserves. This suggests the business model of acquiring dry-gas acreage—drilling several wells to prove the resource, and then flipping the asset—is meeting a bearish market. Liquids-rich acreage still commands interest and a premium.”

E&Ps’ push to emphasize to investors and grow their oil and gas-liquids production began in early 2010, while emphasis leading up to late 2008 was on dry-gas-production growth from the Barnett, Fayetteville and Haynesville plays were headliners before gas prices fell into single digits and finally landed at $4.

At the recent Barclays conference, “management teams took great pains to draw attention away from the gas side of their businesses. Many companies led their presentations with catchy phrases about their new-found oil prowess: ‘back to being an oil company,’ ‘oil story with a gas option,’ ‘a pro-liquids environment,’ ‘liquids factories,’ ‘low-cost-liquids acreage advantage’ and ‘the most misunderstood asset.’ Companies that have already shifted a majority of their production or revenue to liquids trumpeted that fact.”

None of the presenting E&P executives forecasted higher gas prices soon, he adds, in contrast to suggestions in investor presentations a year ago. “In fact, this year marked the first time no company was brave enough to suggest that gas prices were ‘temporarily low.’”

Zenker concludes, “The leveraged gas-growth story has lost much of its appeal. Indeed, many producers said they would not acquire dry gas acreage even at low prices. While producers have delivered the gas production story they promised last year, investors want something else.”

–Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.